In situ thermal processing of a hydrocarbon containing formation to pyrolyze a selected percentage of hydrocarbon material

ABSTRACT

A hydrocarbon containing formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. Heat may be allowed to transfer from one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes a relatively large portion of hydrocarbon material within the selected section of the formation.

PRIORITY CLAIM

This application claims priority to U.S. Provisional Application No.60/199,215 entitled “In Situ Energy Recovery,” filed Apr. 24, 2000, U.S.Provisional Application No. 60/199,214 entitled “In Situ Energy RecoveryFrom Coal,” filed Apr. 24, 2000, and U.S. Provisional Application No.60/199,213 entitled “Emissionless Energy Recovery From Coal,” filed Apr.24, 2000. The above-referenced provisional applications are herebyincorporated by reference as if fully set forth herein.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to methods and systems forproduction of hydrocarbons, hydrogen, and/or other products from varioushydrocarbon containing formations. Certain embodiments relate to in situconversion of hydrocarbons to produce hydrocarbons, hydrogen, and/ornovel product streams from underground hydrocarbon containingformations.

2. Description of Related Art

Hydrocarbons obtained from subterranean (e.g., sedimentary) formationsare often used as energy resources, as feedstocks, and as consumerproducts. Concerns over depletion of available hydrocarbon resourceshave led to development of processes for more efficient recovery,processing and/or use of available hydrocarbon resources. In situprocesses may be used to remove hydrocarbon materials from subterraneanformations. Chemical and/or physical properties of hydrocarbon materialwithin a subterranean formation may need to be changed to allowhydrocarbon material to be more easily removed from the subterraneanformation. The chemical and physical changes may include in situreactions that produce removable fluids, composition changes, solubilitychanges, phase changes, and/or viscosity changes of the hydrocarbonmaterial within the formation. A fluid may be, but is not limited to, agas, a liquid, an emulsion, a slurry and/or a stream of solid particlesthat has flow characteristics similar to liquid flow.

Examples of in situ processes utilizing downhole heaters are illustratedin U.S. Pat. No. 2,634,961 to Ljungstrom, U.S. Pat. No. 2,732,195 toLjungstrom, U.S. Pat. No. 2,780,450 to Ljungstrom, U.S. Pat. No.2,789,805 to Ljungstrom, U.S. Pat. No. 2,923,535 issued to Ljungstrom,and U.S. Pat. No. 4,886,118 to Van Meurs et al., each of which isincorporated by reference as if fully set forth herein.

Application of heat to oil shale formations is described in U.S. Pat.No. 2,923,535 to Ljungstrom and U.S. Pat. No. 4,886,118 to Van Meurs etal., both of which are incorporated by reference as if fully set forthherein. Heat may be applied to the oil shale formation to pyrolyzekerogen within the oil shale formation. The heat may also fracture theformation to increase permeability of the formation. The increasedpermeability may allow formation fluid to travel to a production wellwhere the fluid is removed from the oil shale formation. In someprocesses disclosed by Ljungstrom, for example, an oxygen containinggaseous medium is introduced to a permeable stratum, preferably whilestill hot from a preheating step, to initiate combustion.

A heat source may be used to heat a subterranean formation. Electricalheaters may be used to heat the subterranean formation by radiationand/or conduction. An electrical heater may resistively heat an element.U.S. Pat. No. 2,548,360 to Germain, which is incorporated by referenceas if fully set forth herein, describes an electrical heating elementplaced within a viscous oil within a wellbore. The heater element heatsand thins the oil to allow the oil to be pumped from the wellbore. U.S.Pat. No. 4,716,960 to Eastlund et al., which is incorporated byreference as if fully set forth herein, describes electrically heatingtubing of a petroleum well by passing a relatively low voltage currentthrough the tubing to prevent formation of solids. U.S. Pat. No.5,065,818 to Van Egmond, which is incorporated by reference as if fullyset forth herein, describes an electrical heating element that iscemented into a well borehole without a casing surrounding the heatingelement.

U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement that is positioned within a casing. The heating elementgenerates radiant energy that heats the casing. A granular solid fillmaterial may be placed between the casing and the formation. The casingmay conductively heat the fill material, which in turn conductivelyheats the formation.

U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement. The heating element has an electrically conductive core, asurrounding layer of insulating material, and a surrounding metallicsheath. The conductive core may have a relatively low resistance at hightemperatures. The insulating material may have electrical resistance,compressive strength and heat conductivity properties that arerelatively high at high temperatures. The insulating layer may inhibitarcing from the core to the metallic sheath. The metallic sheath mayhave tensile strength and creep resistance properties that arerelatively high at high temperatures.

U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

Combustion of a fuel may be used to heat a formation. Combusting a fuelto heat a formation may be more economical than using electricity toheat a formation. Several different types of heaters may use fuelcombustion as a heat source that heats a formation. The combustion maytake place in the formation, in a well and/or near the surface.Combustion in the formation may be a fireflood. An oxidizer may bepumped into the formation. The oxidizer may be ignited to advance a firefront towards a production well. Oxidizer pumped into the formation mayflow through the formation along fracture lines in the formation.Ignition of the oxidizer may not result in the fire front flowinguniformly through the formation.

A flameless combustor may be used to combust a fuel within a well. U.S.Pat. No. 5,255,742 to Mikus, U.S. Pat. No. 5,404,952 to Vinegar et al.,U.S. Pat. No. 5,862,858 to Wellington et al., and U.S. Pat. No.5,899,269 to Wellington et al., which are incorporated by reference asif fully set forth herein, describe flameless combustors. Flamelesscombustion may be accomplished by preheating a fuel and combustion airto a temperature above an auto-ignition temperature of the mixture. Thefuel and combustion air may be mixed in a heating zone to combust. Inthe heating zone of the flameless combustor, a catalytic surface may beprovided to lower the auto-ignition temperature of the fuel and airmixture.

Heat may be supplied to a formation from a surface heater. The surfaceheater may produce combustion gases that are circulated throughwellbores to heat the formation. Alternately, a surface burner may beused to heat a heat transfer fluid that is passed through a wellbore toheat the formation. Examples of fired heaters, or surface burners thatmay be used to heat a subterranean formation, are illustrated in U.S.Pat. No. 6,056,057 to Vinegar et al. and U.S. Pat. No. 6,079,499 toMikus et al., which are both incorporated by reference as if fully setforth herein.

Coal is often mined and used as a fuel within an electricity generatingpower plant. Most coal that is used as a fuel to generate electricity ismined. A significant number of coal formations are, however, notsuitable for economical mining. For example, mining coal from steeplydipping coal seams, from relatively thin coal seams (e.g., less thanabout 1 meter thick), and/or from deep coal seams may not beeconomically feasible. Deep coal seams include coal seams that are at,or extend to, depths of greater than about 3000 feet (about 914 m) belowsurface level. The energy conversion efficiency of burning coal togenerate electricity is relatively low, as compared to fuels such asnatural gas. Also, burning coal to generate electricity often generatessignificant amounts of carbon dioxide, oxides of sulfur, and oxides ofnitrogen that are released into the atmosphere.

Synthesis gas may be produced in reactors or in situ within asubterranean formation. Synthesis gas may be produced within a reactorby partially oxidizing methane with oxygen. In situ production ofsynthesis gas may be economically desirable to avoid the expense ofbuilding, operating, and maintaining a surface synthesis gas productionfacility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated byreference as if fully set forth herein, describes a system for in situgasification of coal. A subterranean coal seam is burned from a firstwell towards a production well. Methane, hydrocarbons, H₂, CO, and otherfluids may be removed from the formation through the production well.The H₂ and CO may be separated from the remaining fluid. The H₂ and COmay be sent to fuel cells to generate electricity.

U.S. Pat. No. 4,057,293 to Garrett, which is incorporated by referenceas if fully set forth herein, discloses a process for producingsynthesis gas. A portion of a rubble pile is burned to heat the rubblepile to a temperature that generates liquid and gaseous hydrocarbons bypyrolysis. After pyrolysis, the rubble is further heated, and steam orsteam and air are introduced to the rubble pile to generate synthesisgas.

U.S. Pat. No. 5,554,453 to Steinfeld et al., which is incorporated byreference as if fully set forth herein, describes an ex situ coalgasifier that supplies fuel gas to a fuel cell. The fuel cell produceselectricity. A catalytic burner is used to burn exhaust gas from thefuel cell with an oxidant gas to generate heat in the gasifier.

Carbon dioxide may be produced from combustion of fuel and from manychemical processes. Carbon dioxide may be used for various purposes,such as, but not limited to, a feed stream for a dry ice productionfacility, supercritical fluid in a low temperature supercritical fluidprocess, a flooding agent for coal bed demethanation, and a floodingagent for enhanced oil recovery. Although some carbon dioxide isproductively used, many tons of carbon dioxide are vented to theatmosphere.

Retorting processes for oil shale may be generally divided into twomajor types: aboveground (surface) and underground (in situ).Aboveground retorting of oil shale typically involves mining andconstruction of metal vessels capable of withstanding high temperatures.The quality of oil produced from such retorting may typically be poor,thereby requiring costly upgrading. Aboveground retorting may alsoadversely affect environmental and water resources due to mining,transporting, processing and/or disposing of the retorted material. ManyU.S. patents have been issued relating to aboveground retorting of oilshale. Currently available aboveground retorting processes include, forexample, direct, indirect, and/or combination heating methods.

In situ retorting typically involves retorting oil shale withoutremoving the oil shale from the ground by mining. “Modified” in situprocesses typically require some mining to develop underground retortchambers. An example of a “modified” in situ process includes a methoddeveloped by Occidental Petroleum that involves mining approximately 20%of the oil shale in a formation, explosively rubblizing the remainder ofthe oil shale to fill up the mined out area, and combusting the oilshale by gravity stable combustion in which combustion is initiated fromthe top of the retort. Other examples of “modified” in situ processesinclude the “Rubble In Situ Extraction” (“RISE”) method developed by theLawrence Livermore Laboratory (“LLL”) and radio-frequency methodsdeveloped by IIT Research Institute (“IITRI”) and LLL, which involvetunneling and mining drifts to install an array of radio-frequencyantennas in an oil shale formation.

Obtaining permeability within an oil shale formation (e.g., betweeninjection and production wells) tends to be difficult because oil shaleis often substantially impermeable. Many methods have attempted to linkinjection and production wells, including: hydraulic fracturing such asmethods investigated by Dow Chemical and Laramie Energy Research Center;electrical fracturing (e.g., by methods investigated by Laramie EnergyResearch Center); acid leaching of limestone cavities (e.g., by methodsinvestigated by Dow Chemical); steam injection into permeable nahcolitezones to dissolve the nahcolite (e.g., by methods investigated by ShellOil and Equity Oil); fracturing with chemical explosives (e.g., bymethods investigated by Talley Energy Systems); fracturing with nuclearexplosives (e.g., by methods investigated by Project Bronco); andcombinations of these methods. Many of such methods, however, haverelatively high operating costs and lack sufficient injection capacity.

An example of an in situ retorting process is illustrated in U.S. Pat.No. 3,241,611 to Dougan, assigned to Equity Oil Company, which isincorporated by reference as if fully set forth herein. For example,Dougan discloses a method involving the use of natural gas for conveyingkerogen-decomposing heat to the formation. The heated natural gas may beused as a solvent for thermally decomposed kerogen. The heated naturalgas exercises a solvent-stripping action with respect to the oil shaleby penetrating pores that exist in the shale. The natural gas carrierfluid, accompanied by decomposition product vapors and gases, passesupwardly through extraction wells into product recovery lines, and intoand through condensers interposed in such lines, where the decompositionvapors condense, leaving the natural gas carrier fluid to flow through aheater and into an injection well drilled into the deposit of oil shale.

Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar)contained within relatively permeable formations (e.g., in tar sands)are found in North America, South America, and Asia. Tar can besurface-mined and upgraded to lighter hydrocarbons such as crude oil,naphtha, kerosene, and/or gas oil. Tar sand deposits may, for example,first be mined. Surface milling processes may further separate thebitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

U.S. Pat. No. 5,340,467 to Gregoli et al. and U.S. Pat. No. 5,316,467 toGregoli et al., which are incorporated by reference as if fully setforth herein, describe adding water and a chemical additive to tar sandto form a slurry. The slurry may be separated into hydrocarbons andwater.

U.S. Pat. No. 4,409,090 to Hanson et al., which is incorporated byreference as if fully set forth herein, describes physically-separatingtar sand into a bitumen-rich concentrate that may have some remainingsand. The bitumen-rich concentrate may be further separated from sand ina fluidized bed.

U.S. Pat. No. 5,985,138 to Humphreys and U.S. Pat. No. 5,968,349 toDuyvesteyn et al., which are incorporated by reference as if fully setforth herein, describe mining tar sand and physically separating bitumenfrom the tar sand. Further processing of bitumen in surface facilitiesmay upgrade oil produced from bitumen.

In situ production of hydrocarbons from tar sand may be accomplished byheating and/or injecting a gas into the formation. U.S. Pat. No.5,211,230 to Ostapovich et al. and U.S. Pat. No. 5,339,897 to Leaute,which are incorporated by reference as if fully set forth herein,describe a horizontal production well located in an oil-bearingreservoir. A vertical conduit may be used to inject an oxidant gas intothe reservoir for in situ combustion.

U.S. Pat. No. 2,780,450 to Ljungstrom, which is incorporated byreference as if fully set forth herein, describes heating bituminousgeological formations in situ to convert or crack a liquid tar-likesubstance into oils and gases.

U.S. Pat. No. 4,597,441 to Ware et al, which is incorporated byreference as if fully set forth herein, describes contacting oil, heat,and hydrogen simultaneously in a reservoir. Hydrogenation may enhancerecovery of oil from the reservoir.

U.S. Pat. No. 5,046,559 to Glandt and U.S. Pat. No. 5,060,726 to Glandtet al, which are incorporated by reference as if fully set forth herein,describe preheating a portion of a tar sand formation between aninjector well and a producer well. Steam may be injected from theinjector well into the formation to produce hydrocarbons at the producerwell.

Substantial reserves of heavy hydrocarbons are known to exist informations that have relatively low permeability. For example, billionsof barrels of oil reserves are known to exist in diatomaceous formationsin California. Several methods have been proposed and/or used forproducing heavy hydrocarbons from relatively low permeabilityformations.

U.S. Pat. No. 5,415,231 to Northrop et al., which is incorporated byreference as if fully set forth herein, describes a method forrecovering hydrocarbons (e.g. oil) from a low permeability subterraneanreservoir of the type comprised primarily of diatomite. A first slug orvolume of a heated fluid (e.g. 60% quality steam) is injected into thereservoir at a pressure greater than the fracturing pressure of thereservoir. The well is then shut in and the reservoir is allowed to soakfor a prescribed period (e.g. 10 days or more) to allow the oil to bedisplaced by the steam into the fractures. The well is then produceduntil the production rate drops below an economical level. A second slugof steam is then injected and the cycles are repeated.

U.S. Pat. No. 4,530,401 to Hartman et al., which is incorporated byreference as if fully set forth herein, describes a method for therecovery of viscous oil from a subterranean, viscous oil-containingformation by injecting steam into the formation.

U.S. Pat. No. 5,339,897 to Leaute et al., which is incorporated byreference as if fully set forth herein, describes a method and apparatusfor recovering and/or upgrading hydrocarbons utilizing in situcombustion and horizontal wells.

U.S. Pat. No. 5,431,224 to Laali, which is incorporated by reference asif fully set forth herein, describes a method for improving hydrocarbonflow from low permeability tight reservoir rock.

U.S. Pat. No. 5,297,626 Vinegar et al. and U.S. Pat. No. 5,392,854 toVinegar et al., which are incorporated by reference as if fully setforth herein, describe a process wherein an oil containing subterraneanformation is heated.

As outlined above, there has been a significant amount of effort todevelop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from hydrocarbon containing formations.At present, however, there are still many hydrocarbon containingformations from which hydrocarbons, hydrogen, and/or other productscannot be economically produced. Thus, there is still a need forimproved methods and systems for production of hydrocarbons, hydrogen,and/or other products from various hydrocarbon containing formations.

SUMMARY OF THE INVENTION

In an embodiment, hydrocarbons within a hydrocarbon containing formation(e.g., a formation containing coal, oil shale, heavy hydrocarbons, or acombination thereof) may be converted in situ within the formation toyield a mixture of relatively high quality hydrocarbon products,hydrogen, and other products. One or more heat sources may be used toheat a portion of the hydrocarbon containing formation to temperaturesthat allow pyrolysis of the hydrocarbons. Hydrocarbons, hydrogen, andother formation fluids may be removed from the formation through one ormore production wells. The formation fluids may be removed in a vaporphase. Temperature and pressure in at least a portion of the formationmay be controlled during pyrolysis to yield improved products from theformation.

A heated formation may also be used to produce synthesis gas. In certainembodiments synthesis gas is produced after production of pyrolysisfluids.

A formation may be heated to a temperature greater than 400° C. prior tocontacting a synthesis gas generating fluid with the formation.Contacting a synthesis gas generating fluid, such as water, steam,and/or carbon dioxide, with carbon and/or hydrocarbons within theformation results in generation of synthesis gas if the temperature ofthe carbon is sufficiently high. Synthesis gas generation is, in someembodiments, an endothermic process. Additional heat may be added to theformation during synthesis gas generation to maintain a high temperaturewithin the formation. The heat may be added from heater wells and/orfrom oxidizing carbon and/or hydrocarbons within the formation. Thegenerated synthesis gas may be removed from the formation through one ormore production wells.

After production of pyrolysis fluids and/or synthesis gas, fluid may besequestered within the formation. To store a significant amount of fluidwithin the formation, a temperature of the formation will often need tobe less than about 100° C. Water may be introduced into at least aportion of the formation to generate steam and reduce a temperature ofthe formation. The steam may be removed from the formation. The steammay be utilized for various purposes, including, but not limited to,heating another portion of the formation, generating synthesis gas in anadjacent portion of the formation, generating electricity, and/or as asteam flood in a oil reservoir. After the formation is cooled, fluid(e.g., carbon dioxide) may be pressurized and sequestered in theformation. Sequestering fluid within the formation may result in asignificant reduction or elimination of fluid that is released to theenvironment due to operation of the in situ conversion process.

In an embodiment, one or more heat sources may be installed into aformation to heat the formation. Heat sources may be installed bydrilling openings (well bores) into the formation. In some embodimentsopenings may be formed in the formation using a drill with a steerablemotor and an accelerometer. Alternatively, an opening may be formed intothe formation by geosteered drilling. Alternately, an opening may beformed into the formation by sonic drilling.

One or more heat sources may be disposed within the opening such thatthe heat source may be configured to transfer heat to the formation. Forexample, a heat source may be placed in an open wellbore in theformation. In this manner, heat may conductively and radiativelytransfer from the heat source to the formation. Alternatively, a heatsource may be placed within a heater well that may be packed withgravel, sand, and/or cement. The cement may be a refractory cement.

In some embodiments one or more heat sources may be placed in a patternwithin the formation. For example, in one embodiment, an in situconversion process for hydrocarbons may include heating at least aportion of a hydrocarbon containing formation with an array of heatsources disposed within the formation. In some embodiments, the array ofheat sources can be positioned substantially equidistant from aproduction well. Certain patterns (e.g., triangular arrays, hexagonalarrays, or other array patterns) may be more desirable for specificapplications. In addition, the array of heat sources may be disposedsuch that a distance between each heat source may be less than about 70feet (21 m). In addition, the in situ conversion process forhydrocarbons may include heating at least a portion of the formationwith heat sources disposed substantially parallel to a boundary of thehydrocarbons. Regardless of the arrangement of or distance between theheat sources, in certain embodiments, a ratio of heat sources toproduction wells disposed within a formation may be greater than about5, 8, 10, 20, or more.

Certain embodiments may also include allowing heat to transfer from oneor more of the heat sources to a selected section of the heated portion.In an embodiment, the selected section may be disposed between one ormore heat sources. For example, the in situ conversion process may alsoinclude allowing heat to transfer from one or more heat sources to aselected section of the formation such that heat from one or more of theheat sources pyrolyzes at least some hydrocarbons within the selectedsection. In this manner, the in situ conversion process may includeheating at least a portion of a hydrocarbon containing formation above apyrolyzation temperature of hydrocarbons in the formation. For example,a pyrolyzation temperature may include a temperature of at least about270° C. Heat may be allowed to transfer from one or more of the heatsources to the selected section substantially by conduction.

One or more heat sources may be located within the formation such thatsuperposition of heat produced from one or more heat sources may occur.Superposition of heat may increase a temperature of the selected sectionto a temperature sufficient for pyrolysis of at least some of thehydrocarbons within the selected section. Superposition of heat may varydepending on, for example, a spacing between heat sources. The spacingbetween heat sources may be selected to optimize heating of the sectionselected for treatment. Therefore, hydrocarbons may be pyrolyzed withina larger area of the portion. In this manner, spacing between heatsources may be selected to increase the effectiveness of the heatsources, thereby increasing the economic viability of a selected in situconversion process for hydrocarbons. Superposition of heat tends toincrease the uniformity of heat distribution in the section of theformation selected for treatment.

Various systems and methods may be used to provide heat sources. In anembodiment, a natural distributed combustor system and method may beconfigured to heat at least a portion of a hydrocarbon containingformation. The system and method may first include heating a firstportion of the formation to a temperature sufficient to supportoxidation of at least some of the hydrocarbons therein. One or moreconduits may be disposed within one or more openings. One or more of theconduits may be configured to provide an oxidizing fluid from anoxidizing fluid source into an opening in the formation. The oxidizingfluid may oxidize at least a portion of the hydrocarbons at a reactionzone within the formation. Oxidation may generate heat at the reactionzone. The generated heat may transfer from the reaction zone to apyrolysis zone in the formation. The heat may transfer by conduction,radiation, and/or convection. In this manner, a heated portion of theformation may include the reaction zone and the pyrolysis zone. Theheated portion may also be located substantially adjacent to theopening. One or more of the conduits may also be configured to removeone or more oxidation products from the reaction zone and/or formation.Alternatively, additional conduits may be configured to remove one ormore oxidation products from the reaction zone and/or formation.

In an embodiment, a system and method configured to heat a hydrocarboncontaining formation may include one or more insulated conductorsdisposed in one or more openings in the formation. The openings may beuncased. Alternatively, the openings may include a casing. As such, theinsulated conductors may provide conductive, radiant, or convective heatto at least a portion of the formation. In addition, the system andmethod may be configured to allow heat to transfer from the insulatedconductor to a section of the formation. In some embodiments, theinsulated conductor may include a copper-nickel alloy. In someembodiments, the insulated conductor may be electrically coupled to twoadditional insulated conductors in a 3-phase Y configuration.

In an embodiment, a system and method may include one or more elongatedmembers disposed in an opening in the formation. Each of the elongatedmembers may be configured to provide heat to at least a portion of theformation. One or more conduits may be disposed in the opening. One ormore of the conduits may be configured to provide an oxidizing fluidfrom an oxidizing fluid source into the opening. In certain embodiments,the oxidizing fluid may be configured to substantially inhibit carbondeposition on or proximate to the elongated member.

In an embodiment, a system and method for heating a hydrocarboncontaining formation may include oxidizing a fuel fluid in a heater. Themethod may further include providing at least a portion of the oxidizedfuel fluid into a conduit disposed in an opening in the formation. Inaddition, additional heat may be transferred from an electric heaterdisposed in the opening to the section of the formation. Heat may beallowed to transfer substantially uniformly along a length of theopening.

Energy input costs may be reduced in some embodiments of systems andmethods described above. For example, an energy input cost may bereduced by heating a portion of a hydrocarbon containing formation byoxidation in combination with heating the portion of the formation by anelectric heater. The electric heater may be turned down and/or off whenthe oxidation reaction begins to provide sufficient heat to theformation. In this manner, electrical energy costs associated withheating at least a portion of a formation with an electric heater may bereduced. Thus, a more economical process may be provided for heating ahydrocarbon containing formation in comparison to heating by aconventional method. In addition, the oxidation reaction may bepropagated slowly through a greater portion of the formation such thatfewer heat sources may be required to heat such a greater portion incomparison to heating by a conventional method.

Certain embodiments as described herein may provide a lower cost systemand method for heating a hydrocarbon containing formation. For example,certain embodiments may provide substantially uniform heat transferalong a length of a heater. Such a length of a heater may be greaterthan about 300 m or possibly greater than about 600 m. In addition, incertain embodiments, heat may be provided to the formation moreefficiently by radiation. Furthermore, certain embodiments of systems asdescribed herein may have a substantially longer lifetime than presentlyavailable systems.

In an embodiment, an in situ conversion system and method forhydrocarbons may include maintaining a portion of the formation in asubstantially unheated condition. In this manner, the portion mayprovide structural strength to the formation and/orconfinement/isolation to certain regions of the formation. A processedhydrocarbon containing formation may have alternating heated andsubstantially unheated portions arranged in a pattern that may, in someembodiments, resemble a checkerboard pattern, or a pattern ofalternating areas (e.g., strips) of heated and unheated portions.

In an embodiment, a heat source may advantageously heat only along aselected portion or selected portions of a length of the heater. Forexample, a formation may include several hydrocarbon containing layers.One or more of the hydrocarbon containing layers may be separated bylayers containing little or no hydrocarbons. A heat source may includeseveral discrete high heating zones that may be separated by low heatingzones. The high heating zones may be disposed proximate hydrocarboncontaining layers such that the layers may be heated. The low heatingzones may be disposed proximate to layers containing little or nohydrocarbons such that the layers may not be substantially heated. Forexample, an electrical heater may include one or more low resistanceheater sections and one or more high resistance heater sections. In thismanner, low resistance heater sections of the electrical heater may bedisposed in and/or proximate to layers containing little or nohydrocarbons. In addition, high resistance heater sections of theelectrical heater may be disposed proximate hydrocarbon containinglayers. In an additional example, a fueled heater (e.g., surface burner)may include insulated sections. In this manner, insulated sections ofthe fueled heater may be placed proximate to or adjacent to layerscontaining little or no hydrocarbons. Alternately, a heater withdistributed air and/or fuel may be configured such that little or nofuel may be combusted proximate to or adjacent to layers containinglittle or no hydrocarbons. Such a fueled heater may include flamelesscombustors and natural distributed combustors.

In an embodiment, a heating rate of the formation may be slowly raisedthrough the pyrolysis temperature range. For example, an in situconversion process for hydrocarbons may include heating at least aportion of a hydrocarbon containing formation to raise an averagetemperature of the portion above about 270° C. by a rate less than aselected amount (e.g., about 10° C., 5° C., 3° C., 1° C., 0.5° C., or0.1° C.) per day. In a further embodiment, the portion may be heatedsuch that an average temperature of the selected section may be lessthan about 375° C. or, in some embodiments, less than about 400° C.

In an embodiment, a temperature of the portion may be monitored througha test well disposed in a formation. For example, the test well may bepositioned in a formation between a first heat source and a second heatsource. Certain systems and methods may include controlling the heatfrom the first heat source and/or the second heat source to raise themonitored temperature at the test well at a rate of less than about aselected amount per day. In addition or alternatively, a temperature ofthe portion may be monitored at a production well. In this manner, an insitu conversion process for hydrocarbons may include controlling theheat from the first heat source and/or the second heat source to raisethe monitored temperature at the production well at a rate of less thana selected amount per day.

Certain embodiments may include heating a selected volume of ahydrocarbon containing formation. Heat may be provided to the selectedvolume by providing power to one or more heat sources. Power may bedefined as heating energy per day provided to the selected volume. Apower (Pwr) required to generate a heating rate (h, in units of, forexample, ° C./day) in a selected volume (V) of a hydrocarbon containingformation may be determined by the following equation:Pwr=h*V*C_(V)*ρ_(B). In this equation, an average heat capacity of theformation (C_(V)) and an average bulk density of the formation (ρ_(B))may be estimated or determined using one or more samples taken from thehydrocarbon containing formation.

Certain embodiments may include raising and maintaining a pressure in ahydrocarbon containing formation. Pressure may be, for example,controlled within a range of about 2 bars absolute to about 20 barsabsolute. For example, the process may include controlling a pressurewithin a majority of a selected section of a heated portion of theformation. The controlled pressure may be above about 2 bars absoluteduring pyrolysis. In an alternate embodiment, an in situ conversionprocess for hydrocarbons may include raising and maintaining thepressure in the formation within a range of about 20 bars absolute toabout 36 bars absolute.

In an embodiment, compositions and properties of formation fluidsproduced by an in situ conversion process for hydrocarbons may varydepending on, for example, conditions within a hydrocarbon containingformation.

Certain embodiments may include controlling the heat provided to atleast a portion of the formation such that production of less desirableproducts in the portion may be substantially inhibited. Controlling theheat provided to at least a portion of the formation may also increasethe uniformity of permeability within the formation. For example,controlling the heating of the formation to inhibit production of lessdesirable products may, in some embodiments, include controlling theheating rate to less than a selected amount (e.g., 10° C., 5° C., 3° C.,1° C., 0.5° C., or 0.1° C.) per day.

Controlling pressure, heat and/or heating rates of a selected section ina formation may increase production of selected formation fluids. Forexample, the amount and/or rate of heating may be controlled to produceformation fluids having an American Petroleum Institute (“API”) gravitygreater than about 25. Heat and/or pressure may be controlled to inhibitproduction of olefins in the produced fluids.

Controlling formation conditions to control the pressure of hydrogen inthe produced fluid may result in improved qualities of the producedfluids. In some embodiments it may be desirable to control formationconditions so that the partial pressure of hydrogen in a produced fluidis greater than about 0.5 bars absolute, as measured at a productionwell.

In an embodiment, operating conditions may be determined by measuring atleast one property of the formation. At least the measured propertiesmay be input into a computer executable program. At least one propertyof formation fluids selected to be produced from the formation may alsobe input into the computer executable program. The program may beoperable to determine a set of operating conditions from at least theone or more measured properties. The program may also be configured todetermine the set of operating conditions from at least one property ofthe selected formation fluids. In this manner, the determined set ofoperating conditions may be configured to increase production ofselected formation fluids from the formation.

Certain embodiments may include altering a composition of formationfluids produced from a hydrocarbon containing formation by altering alocation of a production well with respect to a heater well. Forexample, a production well may be located with respect to a heater wellsuch that a non-condensable gas fraction of produced hydrocarbon fluidsmay be larger than a condensable gas fraction of the producedhydrocarbon fluids.

Condensable hydrocarbons produced from the formation will typicallyinclude paraffins, cycloalkanes, mono-aromatics, and di-aromatics asmajor components. Such condensable hydrocarbons may also include othercomponents such as tri-aromatics, etc.

In certain embodiments, a majority of the hydrocarbons in produced fluidmay have a carbon number of less than approximately 25. Alternatively,less than about 15 weight % of the hydrocarbons in the fluid may have acarbon number greater than approximately 25. In other embodiments fluidproduced may have a weight ratio of hydrocarbons having carbon numbersfrom 2 through 4, to methane, of greater than approximately 1 (e.g., foroil shale and heavy hydrocarbons) or greater than approximately 0.3(e.g., for coal). The non-condensable hydrocarbons may include, but arenot limited to, hydrocarbons having carbon numbers less than 5.

In certain embodiments, the API gravity of the hydrocarbons in producedfluid may be approximately 25 or above (e.g., 30, 40, 50, etc.). Incertain embodiments, the hydrogen to carbon atomic ratio in producedfluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).

In certain embodiments, (e.g., when the formation includes coal) fluidproduced from a formation may include oxygenated hydrocarbons. In anexample, the condensable hydrocarbons may include an amount ofoxygenated hydrocarbons greater than about 5% by weight of thecondensable hydrocarbons.

Condensable hydrocarbons of a produced fluid may also include olefins.For example, the olefin content of the condensable hydrocarbons may befrom about 0.1% by weight to about 15% by weight. Alternatively, theolefin content of the condensable hydrocarbons may be from about 0.1% byweight to about 2.5% by weight or, in some embodiments less than about5% by weight.

Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the non-condensablehydrocarbons may be gauged using the ethene/ethane molar ratio. Incertain embodiments the ethene/ethane molar ratio may range from about0.001 to about 0.15.

Fluid produced from the formation may include aromatic compounds. Forexample, the condensable hydrocarbons may include an amount of aromaticcompounds greater than about 20% or about 25% by weight of thecondensable hydrocarbons. The condensable hydrocarbons may also includerelatively low amounts of compounds with more than two rings in them(e.g., tri-aromatics or above). For example, the condensablehydrocarbons may include less than about 1%, 2%, or about 5% by weightof tri-aromatics or above in the condensable hydrocarbons.

In particular, in certain embodiments asphaltenes (i.e., largemulti-ring aromatics that are substantially insoluble in hydrocarbons)make up less than about 0.1% by weight of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0% by weight to about 0.1% by weight or, insome embodiments, less than about 0.3% by weight.

Condensable hydrocarbons of a produced fluid may also include relativelylarge amounts of cycloalkanes. For example, the condensable hydrocarbonsmay include a cycloalkane component of up to 30% by weight (e.g., fromabout 5% by weight to about 30% by weight) of the condensablehydrocarbons.

In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing nitrogen. Forexample, less than about 1% by weight (when calculated on an elementalbasis) of the condensable hydrocarbons is nitrogen (e.g., typically thenitrogen is in nitrogen containing compounds such as pyridines, amines,amides, etc.).

In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing oxygen. Forexample, in certain embodiments (e.g., for oil shale and heavyhydrocarbons) less than about 1% by weight (when calculated on anelemental basis) of the condensable hydrocarbons is oxygen (e.g.,typically the oxygen is in oxygen containing compounds such as phenols,substituted phenols, ketones, etc.). In certain other embodiments (e.g.,for coal) between about 5% and about 30% by weight of the condensablehydrocarbons are typically oxygen containing compounds such as phenols,substituted phenols, ketones, etc. In some instances certain compoundscontaining oxygen (e.g., phenols) may be valuable and, as such, may beeconomically separated from the produced fluid.

In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing sulfur. Forexample, less than about 1% by weight (when calculated on an elementalbasis) of the condensable hydrocarbons is sulfur (e.g., typically thesulfur is in sulfur containing compounds such as thiophenes, mercaptans,etc.).

Furthermore, the fluid produced from the formation may include ammonia(typically the ammonia condenses with the water, if any, produced fromthe formation). For example, the fluid produced from the formation mayin certain embodiments include about 0.05% or more by weight of ammonia.Certain formations may produce larger amounts of ammonia (e.g., up toabout 10% by weight of the total fluid produced may be ammonia).

Furthermore, a produced fluid from the formation may also includemolecular hydrogen (H₂), water, carbon dioxide, hydrogen sulfide, etc.For example, the fluid may include a H₂content between about 10% toabout 80% by volume of the non-condensable hydrocarbons.

Certain embodiments may include heating to yield at least about 15% byweight of a total organic carbon content of at least some of thehydrocarbon containing formation into formation fluids.

In an embodiment, an in situ conversion process for treating ahydrocarbon containing formation may include providing heat to a sectionof the formation to yield greater than about 60% by weight of thepotential hydrocarbon products and hydrogen, as measured by the FischerAssay.

In certain embodiments, heating of the selected section of the formationmay be controlled to pyrolyze at least about 20% by weight (or in someembodiments about 25% by weight) of the hydrocarbons within the selectedsection of the formation.

Certain embodiments may include providing a reducing agent to at least aportion of the formation. A reducing agent provided to a portion of theformation during heating may increase production of selected formationfluids. A reducing agent may include, but is not limited to, molecularhydrogen. For example, pyrolyzing at least some hydrocarbons in ahydrocarbon containing formation may include forming hydrocarbonfragments. Such hydrocarbon fragments may react with each other andother compounds present in the formation. Reaction of these hydrocarbonfragments may increase production of olefin and aromatic compounds fromthe formation. Therefore, a reducing agent provided to the formation mayreact with hydrocarbon fragments to form selected products and/orinhibit the production of non-selected products.

In an embodiment, a hydrogenation reaction between a reducing agentprovided to a hydrocarbon containing formation and at least some of thehydrocarbons within the formation may generate heat. The generated heatmay be allowed to transfer such that at least a portion of the formationmay be heated. A reducing agent such as molecular hydrogen may also beautogenously generated within a portion of a hydrocarbon containingformation during an in situ conversion process for hydrocarbons. In thismanner, the autogenously generated molecular hydrogen may hydrogenateformation fluids within the formation. Allowing formation waters tocontact hot carbon in the spent formation may generate molecularhydrogen. Cracking an injected hydrocarbon fluid may also generatemolecular hydrogen.

Certain embodiments may also include providing a fluid produced in afirst portion of a hydrocarbon containing formation to a second portionof the formation. In this manner, a fluid produced in a first portion ofa hydrocarbon containing formation may be used to produce a reducingenvironment in a second portion of the formation. For example, molecularhydrogen generated in a first portion of a formation may be provided toa second portion of the formation. Alternatively, at least a portion offormation fluids produced from a first portion of the formation may beprovided to a second portion of the formation to provide a reducingenvironment within the second portion. The second portion of theformation may be treated according to any of the embodiments describedherein.

Certain embodiments may include controlling heat provided to at least aportion of the formation such that a thermal conductivity of the portionmay be increased to greater than about 0.5 W/(m° C.) or, in someembodiments, greater than about 0.6 W/(m° C.).

In certain embodiments a mass of at least a portion of the formation maybe reduced due, for example, to the production of formation fluids fromthe formation. As such, a permeability and porosity of at least aportion of the formation may increase. In addition, removing waterduring the heating may also increase the permeability and porosity of atleast a portion of the formation.

Certain embodiments may include increasing a permeability of at least aportion of a hydrocarbon containing formation to greater than about0.01, 0.1, 1, 10, 20 and/or 50 Darcy. In addition, certain embodimentsmay include substantially uniformly increasing a permeability of atleast a portion of a hydrocarbon containing formation. Some embodimentsmay include increasing a porosity of at least a portion of a hydrocarboncontaining formation substantially uniformly.

In certain embodiments, after pyrolysis of a portion of a formation,synthesis gas may be produced from carbon and/or hydrocarbons remainingwithin the formation. Pyrolysis of the portion may produce a relativelyhigh, substantially uniform permeability throughout the portion. Such arelatively high, substantially uniform permeability may allow generationof synthesis gas from a significant portion of the formation atrelatively low pressures. The portion may also have a large surface areaand/or surface area/volume. The large surface area may allow synthesisgas producing reactions to be substantially at equilibrium conditionsduring synthesis gas generation. The relatively high, substantiallyuniform permeability may result in a relatively high recovery efficiencyof synthesis gas, as compared to synthesis gas generation in ahydrocarbon containing formation that has not been so treated.

Synthesis gas may be produced from the formation prior to or subsequentto producing a formation fluid from the formation. For example,synthesis gas generation may be commenced before and/or after formationfluid production decreases to an uneconomical level. In this manner,heat provided to pyrolyze hydrocarbons within the formation may also beused to generate synthesis gas. For example, if a portion of theformation is at a temperature from approximately 270° C. toapproximately 375° C. (or 400° C. in some embodiments) afterpyrolyzation, then less additional heat is generally required to heatsuch portion to a temperature sufficient to support synthesis gasgeneration.

Pyrolysis of at least some hydrocarbons may in some embodiments convertabout 15% by weight or more of the carbon initially available. Synthesisgas generation may convert approximately up to an additional 80% byweight or more of carbon initially available within the portion. In thismanner, in situ production of synthesis gas from a hydrocarboncontaining formation may allow conversion of larger amounts of carboninitially available within the portion. The amount of conversionachieved may, in some embodiments, be limited by subsidence concerns.

Certain embodiments may include providing heat from one or more heatsources to heat the formation to a temperature sufficient to allowsynthesis gas generation (e.g., in a range of approximately 400° C. toapproximately 1200° C. or higher). At a lower end of the temperaturerange, generated synthesis gas may have a high hydrogen (H₂) to carbonmonoxide (CO) ratio. At an upper end of the temperature range, generatedsynthesis gas may include mostly H₂ and CO in lower ratios (e.g.,approximately a 1:1 ratio).

Heat sources for synthesis gas production may include any of the heatsources as described in any of the embodiments set forth herein.Alternatively, heating may include transferring heat from a heattransfer fluid (e.g., steam or combustion products from a burner)flowing within a plurality of wellbores within the formation.

A synthesis gas generating fluid (e.g., liquid water, steam, carbondioxide, air, oxygen, hydrocarbons, and mixtures thereof) may beprovided to the formation. For example, the synthesis gas generatingfluid mixture may include steam and oxygen. In an embodiment, asynthesis gas generating fluid may include aqueous fluid produced bypyrolysis of at least some hydrocarbons within one or more otherportions of the formation. Providing the synthesis gas generating fluidmay alternatively include raising a water table of the formation toallow water to flow into it. Synthesis gas generating fluid may also beprovided through at least one injection wellbore. The synthesis gasgenerating fluid will generally react with carbon in the formation toform H₂, water, methane, CO₂, and/or CO. A portion of the carbon dioxidemay react with carbon in the formation to generate carbon monoxide.Hydrocarbons such as ethane may be added to a synthesis gas generatingfluid. When introduced into the formation, the hydrocarbons may crack toform hydrogen and/or methane. The presence of methane in producedsynthesis gas may increase the heating value of the produced synthesisgas.

Synthesis gas generating reactions are typically endothermic reactions.In an embodiment, an oxidant may be added to a synthesis gas generatingfluid. The oxidant may include, but is not limited to, air, oxygenenriched air, oxygen, hydrogen peroxide, other oxidizing fluids, orcombinations thereof. The oxidant may react with carbon within theformation to exothermically generate heat. Reaction of an oxidant withcarbon in the formation may result in production of CO₂ and/or CO.Introduction of an oxidant to react with carbon in the formation mayeconomically allow raising the formation temperature high enough toresult in generation of significant quantities of H₂ and CO fromhydrocarbons within the formation. Synthesis gas generation may be via abatch process or a continuous process, as is further described herein.

Synthesis gas may be produced from one or more producer wells thatinclude one or more heat sources. Such heat sources may operate topromote production of the synthesis gas with a desired composition.

Certain embodiments may include monitoring a composition of the producedsynthesis gas, and then controlling heating and/or controlling input ofthe synthesis gas generating fluid to maintain the composition of theproduced synthesis gas within a desired range. For example, in someembodiments (e.g., such as when the synthesis gas will be used as afeedstock for a Fischer-Tropsch process) a desired composition of theproduced synthesis gas may have a ratio of hydrogen to carbon monoxideof about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In someembodiments (such as when the synthesis gas will be used as a feedstockto make methanol) such ratio may be about 3:1 (e.g., about 2.8:1 to3.2:1).

Certain embodiments may include blending a first synthesis gas with asecond synthesis gas to produce synthesis gas of a desired composition.The first and the second synthesis gases may be produced from differentportions of the formation.

Synthesis gases described herein may be converted to heavier condensablehydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesisprocess may be configured to convert synthesis gas to branched andunbranched paraffins. Paraffins produced from the Fischer-Tropschprocess may be used to produce other products such as diesel, jet fuel,and naphtha products. The produced synthesis gas may also be used in acatalytic methanation process to produce methane. Alternatively, theproduced synthesis gas may be used for production of methanol, gasolineand diesel fuel, ammonia, and middle distillates. Produced synthesis gasmay be used to heat the formation as a combustion fuel. Hydrogen inproduced synthesis gas may be used to upgrade oil.

Synthesis gas may also be used for other purposes. Synthesis gas may becombusted as fuel. Synthesis gas may also be used for synthesizing awide range of organic and/or inorganic compounds such as hydrocarbonsand ammonia. Synthesis gas may be used to generate electricity, bycombusting it as a fuel, by reducing the pressure of the synthesis gasin turbines, and/or using the temperature of the synthesis gas to makesteam (and then run turbines). Synthesis gas may also be used in anenergy generation unit such as a molten carbonate fuel cell, a solidoxide fuel cell, or other type of fuel cell.

Certain embodiments may include separating a fuel cell feed stream fromfluids produced from pyrolysis of at least some of the hydrocarbonswithin a formation. The fuel cell feed stream may include H₂,hydrocarbons, and/or carbon monoxide. In addition, certain embodimentsmay include directing the fuel cell feed stream to a fuel cell toproduce electricity. The electricity generated from the synthesis gas orthe pyrolyzation fluids in the fuel cell may be configured to powerelectrical heaters, which may be configured to heat at least a portionof the formation. Certain embodiments may include separating carbondioxide from a fluid exiting the fuel cell. Carbon dioxide produced froma fuel cell or a formation may be used for a variety of purposes.

In an embodiment, a portion of a formation that has been pyrolyzedand/or subjected to synthesis gas generation may be allowed to cool ormay be cooled to form a cooled, spent portion within the formation. Forexample, a heated portion of a formation may be allowed to cool bytransference of heat to adjacent portion of the formation. Thetransference of heat may occur naturally or may be forced by theintroduction of heat transfer fluids through the heated portion and intoa cooler portion of the formation. Alternatively, introducing water tothe first portion of the formation may cool the first portion. Waterintroduced into the first portion may be removed from the formation assteam. The removed steam or hot water may be injected into a hot portionof the formation to create synthesis gas.

Cooling the formation may provide certain benefits such as increasingthe strength of the rock in the formation (thereby mitigatingsubsidence), increasing absorptive capacity of the formation, etc.

In an embodiment, a cooled, spent portion of a hydrocarbon containingformation may be used to store and/or sequester other materials such ascarbon dioxide. Carbon dioxide may be injected under pressure into thecooled, spent portion of the formation. The injected carbon dioxide mayadsorb onto hydrocarbons in the formation and/or reside in void spacessuch as pores in the formation. The carbon dioxide may be generatedduring pyrolysis, synthesis gas generation, and/or extraction of usefulenergy.

In an embodiment, produced formation fluids may be stored in a cooled,spent portion of the formation. In some embodiments carbon dioxide maybe stored in relatively deep coal beds, and used to desorb coal bedmethane.

Many of the in situ processes and/or systems described herein may beused to produce hydrocarbons, hydrogen and other formation fluids from arelatively permeable formation that includes heavy hydrocarbons (e.g.,from tar sands). Heating may be used to mobilize the heavy hydrocarbonswithin the formation, and then to pyrolyze heavy hydrocarbons within theformation to form pyrolyzation fluids. Formation fluids produced duringpyrolyzation may be removed from the formation through production wells.

In certain embodiments fluid (e.g., gas) may be provided to a relativelypermeable formation. The gas may be used to pressurize the formation. Apressure in the formation may be selected to control mobilization offluid within the formation. For example, a higher pressure may increasethe mobilization of fluid within the formation such that fluids may beproduced at a higher rate.

In an embodiment, a portion of a relatively permeable formation may beheated to reduce a viscosity of the heavy hydrocarbons within theformation. The reduced viscosity heavy hydrocarbons may be mobilized.The mobilized heavy hydrocarbons may flow to a selected pyrolyzationsection of the formation. A gas may be provided into the relativelypermeable formation to increase a flow of the mobilized heavyhydrocarbons into the selected pyrolyzation section. Such a gas may be,for example, carbon dioxide (the carbon dioxide may be stored in theformation after removal of the heavy hydrocarbons). The heavyhydrocarbons within the selected pyrolyzation section may besubstantially pyrolyzed. Pyrolyzation of the mobilized heavyhydrocarbons may upgrade the heavy hydrocarbons to a more desirableproduct. The pyrolyzed heavy hydrocarbons may be removed from theformation through a production well. In some embodiments, the mobilizedheavy hydrocarbons may be removed from the formation through aproduction well without upgrading or pyrolyzing the heavy hydrocarbons.

Hydrocarbon fluids produced from the formation may vary depending onconditions within the formation. For example, a heating rate of aselected pyrolyzation section may be controlled to increase theproduction of selected products. In addition, pressure within theformation may be controlled to vary the composition of the producedfluids.

Certain systems and methods described herein may be used to treat heavyhydrocarbons in at least a portion of a relatively low permeabilityformation (e.g., in “tight” formations that contain heavy hydrocarbons).Such heavy hydrocarbons may be heated to pyrolyze at least some of theheavy hydrocarbons in a selected section of the formation. Heating mayalso increase the permeability of at least a portion of the selectedsection. Fluids generated from pyrolysis may be produced from theformation.

Certain embodiments for treating heavy hydrocarbons in a relatively lowpermeability formation may include providing heat from one or more heatsources to pyrolyze some of the heavy hydrocarbons and then to vaporizea portion of the heavy hydrocarbons. The heat sources may pyrolyze atleast some heavy hydrocarbons in a selected section of the formation andmay pressurize at least a portion of the selected section. During theheating, the pressure within the formation may increase substantially.The pressure in the formation may be controlled such that the pressurein the formation may be maintained to produce a fluid of a desiredcomposition. Pyrolyzation fluid may be removed from the formation asvapor from one or more heater wells by using the back pressure createdby heating the formation.

Certain embodiments for treating heavy hydrocarbons in at least aportion of a relatively low permeability formation may include heatingto create a pyrolysis zone and heating a selected second section to lessthan the average temperature within the pyrolysis zone. Heavyhydrocarbons may be pyrolyzed in the pyrolysis zone. Heating theselected second section may decrease the viscosity of some of the heavyhydrocarbons in the selected second section to create a low viscosityzone. The decrease in viscosity of the fluid in the selected secondsection may be sufficient such that at least some heated heavyhydrocarbons within the selected second section may flow into thepyrolysis zone. Pyrolyzation fluid may be produced from the pyrolysiszone. In one embodiment, the density of the heat sources in thepyrolysis zone may be greater than in the low viscosity zone.

In certain embodiments it may be desirable to create the pyrolysis zonesand low viscosity zones sequentially over time. The heat sources in aregion near a desired pyrolysis zone may be activated first, resultingin a substantially uniform pyrolysis zone that may be established aftera period of time. Once the pyrolysis zone is established, heat sourcesin the low viscosity zone may be activated sequentially from nearest tofarthest from the pyrolysis zone.

BRIEF DESCRIPTION OF THE DRAWINGS

Further advantages of the present invention may become apparent to thoseskilled in the art with the benefit of the following detaileddescription of the preferred embodiments and upon reference to theaccompanying drawings in which:

FIG. 1 depicts an illustration of stages of heating a hydrocarboncontaining formation;

FIG. 2 depicts a diagram of properties of a hydrocarbon containingformation;

FIG. 3 depicts an embodiment of a heat source pattern;

FIGS. 3a-3 c depict embodiments of heater wells;

FIG. 4 depicts an embodiment of heater wells located in a hydrocarboncontaining formation;

FIG. 5 depicts an embodiment of a pattern of heater wells in ahydrocarbon containing formation;

FIG. 6 depicts an embodiment of a heated portion of a hydrocarboncontaining formation;

FIG. 7 depicts an embodiment of superposition of heat in a hydrocarboncontaining formation;

FIG. 8 and FIG. 9 depict embodiments of a pattern of heat sources andproduction wells in a hydrocarbon containing formation;

FIG. 10 depicts an embodiment of a natural distributed combustor heatsource;

FIG. 11 depicts a portion of an overburden of a formation with a naturaldistributed combustor heat source;

FIG. 12 and FIG. 13 depict alternate embodiments of a naturaldistributed combustor heat source;

FIG. 14 and FIG. 15 depict embodiments of a natural distributedcombustor system for heating a formation;

FIGS. 16-18 depict several embodiments of an insulated conductor heatsource;

FIG. 19 depicts an embodiment of a conductor-in-conduit heat source in aformation;

FIG. 20 depicts an embodiment of a sliding connector;

FIG. 21 depicts an embodiment of a wellhead with a conductor-in-conduitheat source;

FIG. 22 and FIGS. 23a-23 b depict several embodiments of a centralizer;

FIG. 24 depicts an alternate embodiment of a conductor-in-conduit heatsource in a formation;

FIG. 25 depicts an embodiment of a heat source in a formation;

FIG. 26 depicts an embodiment of a surface combustor heat source;

FIG. 27 depicts an embodiment of a conduit for a heat source;

FIG. 28 depicts an embodiment of a flameless combustor heat source;

FIG. 29 depicts an embodiment of using pyrolysis water to generatesynthesis gas in a formation;

FIG. 30 depicts an embodiment of synthesis gas production in aformation;

FIG. 31 depicts an embodiment of continuous synthesis gas production ina formation;

FIG. 32 depicts an embodiment of batch synthesis gas production in aformation;

FIG. 33 depicts an embodiment of producing energy with synthesis gasproduced from a hydrocarbon containing formation;

FIG. 34 depicts an embodiment of producing energy with pyrolyzationfluid produced from a hydrocarbon containing formation;

FIG. 35 depicts an embodiment of synthesis gas production from aformation;

FIG. 36 depicts an embodiment of sequestration of carbon dioxideproduced during pyrolysis in a hydrocarbon containing formation;

FIG. 37 depicts an embodiment of producing energy with synthesis gasproduced from a hydrocarbon containing formation;

FIG. 38 depicts an embodiment of a Fischer-Tropsch process usingsynthesis gas produced from a hydrocarbon containing formation;

FIG. 39 depicts an embodiment of a Shell Middle Distillates processusing synthesis gas produced from a hydrocarbon containing formation;

FIG. 40 depicts an embodiment of a catalytic methanation process usingsynthesis gas produced from a hydrocarbon containing formation;

FIG. 41 depicts an embodiment of production of ammonia and urea usingsynthesis gas produced from a hydrocarbon containing formation;

FIG. 42 depicts an embodiment of production of ammonia using synthesisgas produced from a hydrocarbon containing formation;

FIG. 43 depicts an embodiment of preparation of a feed stream for anammonia process;

FIGS. 44-48 depict several embodiments for treating a relativelypermeable formation;

FIG. 49 and FIG. 50 depict embodiments of heat sources in a relativelypermeable formation;

FIGS. 51-56 depict several embodiments of heat sources in a relativelylow permeability formation;

FIGS. 57-70 depict several embodiments of a heat source and productionwell pattern;

FIG. 71 depicts an embodiment of surface facilities for treating aformation fluid;

FIG. 72 depicts an embodiment of a catalytic flameless distributedcombustor;

FIG. 73 depicts an embodiment of surface facilities for treating aformation fluid;

FIG. 74 depicts an embodiment of a square pattern of heat sources andproduction wells;

FIG. 75 depicts an embodiment of a heat source and production wellpattern;

FIG. 76 depicts an embodiment of a triangular pattern of heat sources;

FIG. 76a depicts an embodiment of a square pattern of heat sources;

FIG. 77 depicts an embodiment of a hexagonal pattern of heat sources;

FIG. 77a depicts an embodiment of a 12 to 1 pattern of heat sources;

FIG. 78 depicts a temperature profile for a triangular pattern of heatsources;

FIG. 79 depicts a temperature profile for a square pattern of heatsources;

FIG. 79a depicts a temperature profile for a hexagonal pattern of heatsources;

FIG. 80 depicts a comparison plot between the average patterntemperature and temperatures at the coldest spots for various patternsof heat sources;

FIG. 81 depicts a comparison plot between the average patterntemperature and temperatures at various spots within triangular andhexagonal patterns of heat sources;

FIG. 81a depicts a comparison plot between the average patterntemperature and temperatures at various spots within a square pattern ofheat sources;

FIG. 81b depicts a comparison plot between temperatures at the coldestspots of various pattern of heat sources;

FIG. 82 depicts extension of a reaction zone in a heated formation overtime;

FIG. 83 and FIG. 84 depict the ratio of conductive heat transfer toradiative heat transfer in a formation;

FIGS. 85-88 depict temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation;

FIG. 89 depicts a retort and collection system;

FIG. 90 depicts pressure versus temperature in an oil shale formationduring pyrolysis;

FIG. 91 depicts quality of oil produced from an oil shale formation;

FIG. 92 depicts ethene to ethane ratio produced from an oil shaleformation as a function of temperature and pressure;

FIG. 93 depicts yield of fluids produced from an oil shale formation asa function of temperature and pressure;

FIG. 94 depicts a plot of oil yield produced from treating an oil shaleformation;

FIG. 95 depicts yield of oil produced from treating an oil shaleformation;

FIG. 96 depicts hydrogen to carbon ratio of hydrocarbon condensateproduced from an oil shale formation as a function of temperature andpressure;

FIG. 97 depicts olefin to paraffin ratio of hydrocarbon condensateproduced from an oil shale formation as a function of pressure andtemperature;

FIG. 98 depicts relationships between properties of a hydrocarbon fluidproduced from an oil shale formation;

FIG. 99 depicts quantity of oil produced from an oil shale formation asa function of partial pressure of H₂;

FIG. 100 depicts ethene to ethane ratios of fluid produced from an oilshale formation as a function of temperature and pressure;

FIG. 101 depicts hydrogen to carbon atomic ratios of fluid produced froman oil shale formation as a function of temperature and pressure;

FIG. 102 depicts an embodiment of an apparatus for a drum experiment;

FIG. 103 depicts a plot of ethene to ethane ratio versus hydrogenconcentration;

FIG. 104 depicts a heat source and production well pattern for a fieldexperiment in an oil shale formation;

FIG. 105 depicts a cross-sectional view of the field experiment;

FIG. 106 depicts a plot of temperature within the oil shale formationduring the field experiment;

FIG. 107 depicts pressure within the oil shale formation during thefield experiment;

FIG. 108 depicts a plot of API gravity of a fluid produced from the oilshale formation during the field experiment versus time;

FIG. 109 depicts average carbon numbers of fluid produced from the oilshale formation during the field experiment versus time;

FIG. 110 depicts density of fluid produced from the oil shale formationduring the field experiment versus time;

FIG. 111 depicts a plot of weight percent of hydrocarbons within fluidproduced from the oil shale formation during the field experiment;

FIG. 112 depicts a plot of an average yield of oil from the oil shaleformation during the field experiment;

FIG. 113 depicts experimental data from laboratory experiments on oilshale;

FIG. 114 depicts total hydrocarbon production and liquid phase fractionversus time of a fluid produced from an oil shale formation;

FIG. 115 depicts weight percent of paraffins versus vitrinitereflectance;

FIG. 116 depicts weight percent of cycloalkanes in produced oil versusvitrinite reflectance;

FIG. 117 depicts weight percentages of paraffins and cycloalkanes inproduced oil versus vitrinite reflectance;

FIG. 118 depicts phenol weight percent in produced oil versus vitrinitereflectance;

FIG. 119 depicts aromatic weight percent in produced oil versusvitrinite reflectance;

FIG. 120 depicts ratio of paraffins and aliphatics to aromatics versusvitrinite reflectance;

FIG. 121 depicts yields of paraffins versus vitrinite reflectance;

FIG. 122 depicts yields of cycloalkanes versus vitrinite reflectance;

FIG. 123 depicts yields of cycloalkanes and paraffins versus vitrinitereflectance;

FIG. 124 depicts yields of phenol versus vitrinite reflectance;

FIG. 125 depicts API gravity as a function of vitrinite reflectance;

FIG. 126 depicts yield of oil from a coal formation as a function ofvitrinite reflectance;

FIG. 127 depicts CO₂ yield from coal having various vitrinitereflectances;

FIG. 128 depicts CO₂ yield versus atomic O/C ratio for a coal formation;

FIG. 129 depicts a schematic of a coal cube experiment;

FIG. 130 depicts in situ temperature profiles for electrical resistanceheaters, and natural distributed combustion heaters;

FIG. 131 depicts equilibrium gas phase compositions produced fromexperiments on a coal cube;

FIG. 132 depicts cumulative production of gas as a function oftemperature produced by heating a coal cube;

FIG. 133 depicts cumulative condensable hydrocarbons as a function oftemperature produced by heating a coal cube;

FIG. 134 depicts the compositions of condensable hydrocarbons producedwhen various ranks of coal were treated;

FIG. 135 depicts thermal conductivity of coal versus temperature;

FIG. 136 depicts a cross-sectional view of an in situ experimental fieldtest;

FIG. 137 depicts locations of heat sources and wells in an experimentalfield test;

FIG. 138 and FIG. 139 depict temperature versus time in an experimentalfield test;

FIG. 140 depicts volume of oil produced from an experimental field testas a function of time;

FIG. 141 depicts carbon number distribution of fluids produced from anexperimental field test;

FIG. 142 depicts weight percent of a hydrocarbon produced from twolaboratory experiments on coal from the field test site versus carbonnumber distribution;

FIG. 143 depicts fractions from separation of coal oils treated byFischer assay and treated by slow heating in a coal cube experiment;

FIG. 144 depicts percentage ethene to ethane produced from a coalformation as a function of heating rate in a laboratory test;

FIG. 145 depicts product quality of fluids produced from a coalformation as a function of heating rate in a laboratory test;

FIG. 146 depicts weight percentages of various fluids produced from acoal formation for various heating rates in a laboratory test;

FIG. 147 depicts CO₂ produced at three different locations versus timein an experimental field test;

FIG. 148 depicts volatiles produced from a coal formation in anexperimental field test versus cumulative energy content;

FIG. 149 depicts volume of gas produced from a coal formation in anexperimental field test as a function of time;

FIG. 150 depicts volume of oil produced from a coal formation in anexperimental field test as a function of energy input;

FIG. 151 depicts synthesis gas production from the coal formation in anexperimental field test versus the total water inflow;

FIG. 152 depicts additional synthesis gas production from the coalformation in an experimental field test due to injected steam;

FIG. 153 depicts the effect of methane injection into a heatedformation;

FIG. 154 depicts the effect of ethane injection into a heated formation;

FIG. 155 depicts the effect of propane injection into a heatedformation;

FIG. 156 depicts the effect of butane injection into a heated formation;

FIG. 157 depicts composition of gas produced from a formation versustime;

FIG. 158 depicts synthesis gas conversion versus time;

FIG. 159 depicts calculated equilibrium gas dry mole fractions for areaction of coal with water;

FIG. 160 depicts calculated equilibrium gas wet mole fractions for areaction of coal with water;

FIG. 161 depicts an example of pyrolysis and synthesis gas productionstages in a coal formation;

FIG. 162 depicts an example of low temperature in situ synthesis gasproduction;

FIG. 163 depicts an example of high temperature in situ synthesis gasproduction;

FIG. 164 depicts an example of in situ synthesis gas production in ahydrocarbon containing formation;

FIG. 165 depicts a plot of cumulative adsorbed methane and carbondioxide versus pressure in a coal formation;

FIG. 166 depicts an embodiment of in situ synthesis gas productionintegrated with a Fischer-Tropsch process;

FIG. 167 depicts a comparison between numerical simulation data andexperimental field test data of synthesis gas composition produced as afunction of time;

FIG. 168 depicts weight percentages of carbon compounds versus carbonnumber produced from a heavy hydrocarbon containing formation;

FIG. 169 depicts weight percentages of carbon compounds produced from aheavy hydrocarbon containing formation versus heating rate and pressure;

FIG. 170 depicts a plot of oil production versus time in a heavyhydrocarbon containing formation;

FIG. 171 depicts ratio of heat content of fluids produced from a heavyhydrocarbon containing formation to heat input versus time;

FIG. 172 depicts numerical simulation data of weight percentage versuscarbon number distribution produced from a heavy hydrocarbon containingformation;

FIG. 173 depicts H₂ mole percent in gases produced from heavyhydrocarbon drum experiments.

FIG. 174 depicts API gravity of liquids produced from heavy hydrocarbondrum experiments;

FIG. 175 depicts a plot of hydrocarbon liquids production over time foran in situ field experiment;

FIG. 176 depicts a plot of hydrocarbon liquids, gas, and water for an insitu field experiment;

FIG. 177 depicts pressure at wellheads as a function of time from anumerical simulation;

FIG. 178 depicts production rate of carbon dioxide and methane as afunction of time from a numerical simulation;

FIG. 179 depicts cumulative methane produced and net carbon dioxideinjected as a function of time from a numerical simulation;

FIG. 180 depicts pressure at wellheads as a function of time from anumerical simulation;

FIG. 181 depicts production rate of carbon dioxide as a function of timefrom a numerical simulation; and

FIG. 182 depicts cumulative net carbon dioxide injected as a function oftime from a numerical simulation.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

The following description generally relates to systems and methods fortreating a hydrocarbon containing formation (e.g., a formationcontaining coal (including lignite, sapropelic coal, etc.), oil shale,carbonaceous shale, shungites, kerogen, oil, kerogen and oil in a lowpermeability matrix, heavy hydrocarbons, asphaltites, natural mineralwaxes, formations wherein kerogen is blocking production of otherhydrocarbons, etc.). Such formations may be treated to yield relativelyhigh quality hydrocarbon products, hydrogen, and other products.

As used herein, “a method of treating a hydrocarbon containingformation” may be

“Hydrocarbons” are generally defined as molecules formed primarily bycarbon and hydrogen atoms. Hydrocarbons may also include other elements,such as, but not limited to, halogens, metallic elements, nitrogen,oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to,kerogen, bitumen, pyrobitumen, and oils. Hydrocarbons may be locatedwithin or adjacent to mineral matrices within the earth. Matrices mayinclude, but are not limited to, sedimentary rock, sands, silicilytes,carbonates, diatomites, and other porous media. used interchangeablywith “an in situ conversion process for hydrocarbons.”

“Hydrocarbons” are generally defined as molecules formed primarily bycarbon and hydrogen atoms. Hydrocarbons may also include other elements,such as, but not limited to, halogens, metallic elements, nitrogen,oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to,kerogen, bitumen, pyrobitumen, and oils. Hydrocarbons may be locatedwithin or adjacent to mineral matrices within the earth. Matrices mayinclude, but are not limited to, sedimentary rock, sands, silicilytes,carbonates, diatomites, and other porous media.

“Kerogen” is generally defined as a solid, insoluble hydrocarbon thathas been converted by natural degradation (e.g., by diagenesis) and thatprincipally contains carbon, hydrogen, nitrogen, oxygen, and sulfur.Coal and oil shale are typical examples of materials that containkerogens. “Bitumen” is generally defined as a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulphide. “Oil” is generally defined as a fluid containing a complexmixture of condensable hydrocarbons.

The terms “formation fluids” and “produced fluids” generally refer tofluids removed from a hydrocarbon containing formation and may includepyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water(steam). The term “mobilized fluid” generally refers to fluids withinthe formation that are able to flow because of thermal treatment of theformation. Formation fluids may include hydrocarbon fluids as well asnon-hydrocarbon fluids. As used herein, “hydrocarbon fluids” generallyrefer to compounds including primarily hydrogen and carbon. Hydrocarbonfluids may include other elements in addition to hydrogen and carbonsuch as, but not limited to, nitrogen, oxygen, and sulfur.Non-hydrocarbon fluids may include, but are not limited to, hydrogen(“H₂”), nitrogen (“N₂”), carbon monoxide, carbon dioxide, hydrogensulfide, water, and ammonia.

A “carbon number” generally refers to a number of carbon atoms within amolecule. As described herein, carbon number distributions aredetermined by true boiling point distribution and gas liquidchromatography.

A “heat source” is generally defined as any system configured to provideheat to at least a portion of a formation. For example, a heat sourcemay include electrical heaters such as an insulated conductor, anelongated member, and a conductor disposed within a conduit, asdescribed in embodiments herein. A heat source may also include heatsources that generate heat by burning a fuel external to or within aformation such as surface burners, flameless distributed combustors, andnatural distributed combustors, as described in embodiments herein. Inaddition, it is envisioned that in some embodiments heat provided to orgenerated in one or more heat sources may by supplied by other sourcesof energy. The other sources of energy may directly heat a formation, orthe energy may be applied to a transfer media that directly orindirectly heats the formation. It is to be understood that one or moreheat sources that are applying heat to a formation may use differentsources of energy. Thus, for example, for a given formation some heatsources may supply heat from electric resistance heaters, some heatsources may provide heat from combustion, and some heat sources mayprovide heat from one or more other energy sources (e.g., chemicalreactions, solar energy, wind energy, or other sources of renewableenergy). A chemical reaction may include an exothermic reaction such as,but not limited to, an oxidation reaction that may take place in atleast a portion of a formation. A heat source may also include a heaterthat may be configured to provide heat to a zone proximate to and/orsurrounding a heating location such as a heater well. Heaters may be,but are not limited to, electricheaters, burners, and naturaldistributed combustors.

A “heater” is generally defined as any system configured to generateheat in a well or a near wellbore region. A “unit of heat sources”refers to a minimal number of heat sources that form a template that isrepeated to create a pattern of heat sources within a formation. Forexample, a heater may generate heat by burning a fuel external to orwithin a formation such as surface burners, flameless distributedcombustors, and natural distributed combustors, as described inembodiments herein.

The term “wellbore” generally refers to a hole in a formation made bydrilling. A wellbore may have a substantially circular cross-section, ora cross-section in other shapes as well (e.g., circles, ovals, squares,rectangles, triangles, slits, or other regular or irregular shapes). Asused herein, the terms “well” and “opening,” when referring to anopening in the formation, may also be used interchangeably with the term“wellbore.”

As used herein, the phrase “natural distributed combustor” generallyrefers to a heater that uses an oxidant to oxidize at least a portion ofthe carbon in the formation to generate heat, and wherein the oxidationtakes place in a vicinity proximate to a wellbore. Most of thecombustion products produced in the natural distributed combustor areremoved through the wellbore.

The term “orifices,” as used herein, generally describes openings havinga wide variety of sizes and cross-sectional shapes including, but notlimited to, circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes.

As used herein, a “reaction zone” generally refers to a volume of ahydrocarbon containing formation that is subjected to a chemicalreaction such as an oxidation reaction.

As used herein, the term “insulated conductor” generally refers to anyelongated material that may conduct electricity and that is covered, inwhole or in part, by an electrically insulating material. The term“self-controls” generally refers to controlling an output of a heaterwithout external control of any type.

“Pyrolysis” is generally defined as the breaking of chemical bonds dueto the application of heat. For example, pyrolysis may includetransforming a compound into one or more other substances by heat alone.In the context of this patent, heat for pyrolysis may originate in anoxidation reaction and then such heat may be transferred to a section ofthe formation to cause pyrolysis.

As used herein, a “pyrolyzation fluid” or “pyrolysis products” generallyrefers to a fluid produced substantially during pyrolysis ofhydrocarbons. As used herein, a “pyrolysis zone” generally refers to avolume of hydrocarbon containing formation that is reacted or reactingto form a pyrolyzation fluid.

“Cracking” generally refers to a process involving decomposition andmolecular recombination of organic compounds wherein a number ofmolecules becomes larger. In cracking, a series of reactions take placeaccompanied by a transfer of hydrogen atoms between molecules. Crackingfundamentally changes the chemical structure of the molecules. Forexample, naphtha may undergo a thermal cracking reaction to form etheneand H₂.

The term “superposition of heat” is generally defined as providing heatfrom at least two heat sources to a selected section of the portion ofthe formation such that the temperature of the formation at least at onelocation between the two wells is influenced by at least two heatsources.

The term “fingering” generally refers to injected fluids bypassingportions of a formation because of variations in transportcharacteristics (e.g., permeability).

“Thermal conductivity” is generally defined as the property of amaterial that describes the rate at which heat flows, in steady state,between two surfaces of the material for a given temperature differencebetween the two surfaces.

“Fluid pressure” is generally defined as a pressure generated by a fluidwithin a formation. “Lithostatic pressure” is sometimes referred to aslithostatic stress and is generally defined as a pressure within aformation equal to a weight per unit area of an overlying rock mass.“Hydrostatic pressure” is generally defined as a pressure within aformation exerted by a column of water.

“Condensable hydrocarbons” means the hydrocarbons that condense at 25°C. at one atmosphere absolute pressure. Condensable hydrocarbons mayinclude a mixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” means the hydrocarbons that do notcondense at 25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

“Olefins” are generally defined as unsaturated hydrocarbons having oneor more non-aromatic carbon-to-carbon double bonds.

“Urea” is generally described by a molecular formula of NH₂—CO—NH₂. Ureacan be used as a fertilizer.

“Synthesis gas” is generally defined as a mixture including hydrogen andcarbon monoxide used for synthesizing a wide range of compounds.Additional components of synthesis gas may include water, carbondioxide, nitrogen, methane and other gases. Synthesis gas may begenerated by a variety of processes and feedstocks.

“Reforming” is generally defined as the reaction of hydrocarbons (suchas methane or naphtha) with steam to produce CO and H₂ as majorproducts. Generally it is conducted in the presence of a catalystalthough it can be performed thermally without the presence of acatalyst.

“Sequestration” generally refers to storing a gas that is a by-productof a process rather than venting the gas to the atmosphere.

The term “dipping” is generally defined as sloping downward or incliningfrom a plane parallel to the earth's surface, assuming the plane is flat(i.e., a “horizontal” plane). A “dip” is generally defined as an anglethat a stratum or similar feature may make with a horizontal plane. A“steeply dipping” hydrocarbon containing formation generally refers to ahydrocarbon containing formation lying at an angle of at least 20° froma horizontal plane. As used herein, “down dip” generally refers todownward along a direction parallel to a dip in a formation. As usedherein, “up dip” generally refers to upward along a direction parallelto a dip of a formation. “Strike” refers to the course or bearing ofhydrocarbon material that is normal to the direction of the dip.

The term “subsidence” is generally defined as downward movement of aportion of a formation relative to an initial elevation of the surface.

“Thickness” of a layer refers to the thickness of a cross-section of alayer, wherein the cross-section is normal to a face of the layer.

“Coring” is generally defined as a process that generally includesdrilling a hole into a formation and removing a substantially solid massof the formation from the hole.

A “surface unit” is generally defined as an ex situ treatment unit.

“Middle distillates” generally refers to hydrocarbon mixtures with aboiling point range that may correspond substantially with that ofkerosene and gas oil fractions obtained in a conventional atmosphericdistillation of crude oil material. The middle distillate boiling pointrange may include temperatures between about 150° C. and about 360° C.,with a fraction boiling point between about 200° C. and about 360° C.Middle distillates may be referred to as gas oil.

A “boiling point cut” is generally defined as a hydrocarbon liquidfraction that may be separated from hydrocarbon liquids when thehydrocarbon liquids are heated to a boiling point range of the fraction.

The term “selected mobilized section” refers to a section of arelatively permeable formation that is at an average temperature withina mobilization temperature range. The term “selected pyrolyzationsection” refers to a section of a relatively permeable formation that isat an average temperature within a pyrolyzation temperature range.

“Enriched air” generally refers to air having a larger mole fraction ofoxygen than air in the atmosphere. Enrichment of air is typically doneto increase its combustion-supporting ability.

“Heavy hydrocarbons” are generally defined as viscous hydrocarbonfluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluidssuch as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may includecarbon and hydrogen, as well as smaller concentrations of sulfur,oxygen, and nitrogen. Additional elements may also be present in heavyhydrocarbons in trace amounts. Heavy hydrocarbons may be classified byAPI gravity. Heavy hydrocarbons generally have an API gravity belowabout 20°. Heavy oil, for example, generally has an API gravity of about10-20° whereas tar generally has an API gravity below about 10°. Theviscosity of heavy hydrocarbons is generally greater than about 300centipoise at 15° C. Tar generally has a viscosity greater than about10,000 centipoise at 15° C. Heavy hydrocarbons may also includearomatics, or other complex ring hydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. Therelatively permeable formation may include heavy hydrocarbons entrainedin, for example, sand or carbonate. “Relatively permeable” is defined,with respect to formations or portions thereof, as an averagepermeability of 10 millidarcy or more (e.g., 10 or 100 millidarcy).“Relatively low permeability” is defined, with respect to formations orportions thereof, as an average permeability of less than about 10millidarcy. One Darcy is equal to about 0.99 square micrometers. Animpermeable layer generally has a permeability of less than about 0.1millidarcy.

The term “upgrade” refers to increasing the API gravity of heavyhydrocarbons.

The phrase “off peak” times generally refers to times of operation whereutility energy is less commonly used and, therefore, less expensive.

The term “low viscosity zone” generally refers to a section of aformation where at least a portion of the fluids are mobilized.

Tar contained in sand in a formation is generally referred to as a “tarsand formation.”

“Thermal fracture” refers to fractures created in a formation caused byexpansion or contraction of a formation and/or fluids within theformation, which is in turn caused by increasing/decreasing thetemperature of the formation and/or fluids within the formation, and/orby increasing/decreasing a pressure of fluids within the formation dueto heating.

“Vertical hydraulic fracture” refers to a fracture at least partiallypropagated along a vertical plane in a formation, wherein the fractureis created through injection of fluids into a formation.

Hydrocarbons in formations may be treated in various ways to producemany different products. In certain embodiments such formations may betreated in stages. FIG. 1 illustrates several stages of heating ahydrocarbon containing formation. FIG. 1 also depicts an example ofyield (barrels of oil equivalent per ton) (y axis) of formation fluidsfrom a hydrocarbon containing formation versus temperature (° C.) (xaxis) of the formation.

Desorption of methane and vaporization of water occurs during stage 1heating in FIG. 1. For example, when a hydrocarbon containing formationis initially heated, hydrocarbons in the formation may desorb adsorbedmethane. The desorbed methane may be produced from the formation. If thehydrocarbon containing formation is heated further, water within thehydrocarbon containing formation may be vaporized. In addition, thevaporized water may be produced from the formation. Heating of theformation through stage 1 is in many instances preferably performed asquickly as possible.

After stage 1 heating, the formation may be heated further such that atemperature within the formation reaches (at least) an initialpyrolyzation temperature (e.g., the temperature at the lower end of thetemperature range shown as stage 2). A pyrolysis temperature range mayvary depending on types of hydrocarbons within the formation. Forexample, a pyrolysis temperature range may include temperatures betweenabout 250° C. and about 900° C. In an alternative embodiment, apyrolysis temperature range may include temperatures between about 270°C. to about 400° C. Hydrocarbons within the formation may be pyrolyzedthroughout stage 2.

Formation fluids including pyrolyzation fluids may be produced from theformation. The pyrolyzation fluids may include, but are not limited to,hydrocarbons, hydrogen, carbon dioxide, carbon monoxide, hydrogensulfide, ammonia, nitrogen, water and mixtures thereof; As thetemperature of the formation increases, the amount of condensablehydrocarbons in the produced formation fluid tends to decrease, and theformation will in many instances tend to produce mostly methane andhydrogen. If a hydrocarbon containing formation is heated throughout anentire pyrolysis range, the formation may produce only small amounts ofhydrogen towards an upper limit of the pyrolysis range. After all of theavailable hydrogen is depleted, a minimal amount of fluid productionfrom the formation will typically occur.

After pyrolysis of hydrocarbons, a large amount of carbon and somehydrogen may still be present in the formation. A significant portion ofremaining carbon in the formation can be produced from the formation inthe form of synthesis gas. Synthesis gas generation may take placeduring stage 3 heating as shown in FIG. 1. Stage 3 may include heating ahydrocarbon containing formation to a temperature sufficient to allowsynthesis gas generation. For example, synthesis gas may be producedwithin a temperature range from about 400° C. to about 1200° C. Thetemperature of the formation when the synthesis gas generating fluid isintroduced to the formation will in many instances determine thecomposition of synthesis gas produced within the formation. If asynthesis gas generating fluid is introduced into a formation at atemperature sufficient to allow synthesis gas generation, then synthesisgas may be generated within the formation. The generated synthesis gasmay be removed from the formation. A large volume of synthesis gas maybe produced during generation of synthesis gas.

Depending on the amounts of fluid produced, total energy content offluids produced from a hydrocarbon containing formation may in someinstances stay relatively constant throughout pyrolysis and synthesisgas generation. For example, during pyrolysis, at relatively lowformation temperatures, a significant portion of the produced fluid maybe condensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons, and more non-condensable formation fluids maybe produced. In this manner, energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instanceincrease substantially, thereby compensating for the decreased energycontent.

As explained below, the van Krevelen diagram shown in FIG. 2 depicts aplot of atomic hydrogen to carbon ratio (y axis) versus atomic oxygen tocarbon ratio (x axis) for various types of kerogen. This diagram showsthe maturation sequence for various types of kerogen that typicallyoccurs over geologic time due to temperature, pressure, and biochemicaldegradation. The maturation may be accelerated by heating in situ at acontrolled rate and/or a controlled pressure.

A van Krevelen diagram may be useful for selecting a resource forpracticing various embodiments described herein (see discussion below):Treating a formation containing kerogen in region 5 will in manyinstances produce, e.g., carbon dioxide, non-condensable hydrocarbons,hydrogen, and water, along with a relatively small amount of condensablehydrocarbons. Treating a formation containing kerogen in region 7 willin many instances produce, e.g., carbon, condensable and non-condensablehydrocarbons, carbon dioxide, hydrogen, and water. Treating a formationcontaining kerogen in region 9 will in many instances produce, e.g.,methane and hydrogen. A formation containing kerogen in region 7, forexample, may in many instances be selected for treatment because doingso will tend to produce larger quantities of valuable hydrocarbons, andlower quantities of undesirable products such as carbon dioxide andwater, since the region 7 kerogen has already undergone dehydrationand/or decarboxylation over geological time. In addition, region 7kerogen can also be further treated to make other useful products (e.g.,methane, hydrogen, and/or synthesis gas) as such kerogen transforms toregion 9 kerogen.

If a formation containing kerogen in region 5 or 7 was selected fortreatment, then treatment pursuant to certain embodiments describedherein would cause such kerogen to transform during treatment (seearrows in FIG. 2) to a region having a higher number (e.g., region 5kerogen could transform to region 7 kerogen and possibly then to region9 kerogen, or region 7 kerogen could transform to region 9 kerogen).Thus, certain embodiments described herein cause expedited maturation ofkerogen, thereby allowing production of valuable products.

If region 5 kerogen, for example, is treated, then substantial carbondioxide may be produced due to decarboxylation of hydrocarbons in theformation. In addition, treating region 5 kerogen may also produce somehydrocarbons (e.g., primarily methane). Treating region 5 kerogen mayalso produce substantial amounts of water due to dehydration of kerogenin the formation. Production of such compounds from a formation mayleave residual hydrocarbons relatively enriched in carbon. Oxygencontent of the hydrocarbons will in many instances decrease faster thana hydrogen content of the hydrocarbons during production of suchcompounds. Therefore, as shown in FIG. 2, production of such compoundsmay result in a larger decrease in the atomic oxygen to carbon ratiothan a decrease in the atomic hydrogen to carbon ratio (see region 5arrows in FIG. 2 which depict more horizontal than vertical movement).

If region 7 kerogen is treated, then typically at least some of thehydrocarbons in the formation are pyrolyzed to produce condensable andnon-condensable hydrocarbons. For example, treating region 7 kerogen mayresult in production of oil from hydrocarbons, as well as some carbondioxide and water (albeit generally less carbon dioxide and water thanis produced when the region 5 kerogen is treated). Therefore, the atomichydrogen to carbon ratio of the kerogen will in many instances decreaserapidly as the kerogen in region 7 is treated. The atomic oxygen tocarbon ratio of the region 7 kerogen, however, will in many instancesdecrease much slower than the atomic hydrogen to carbon ratio of theregion 7 kerogen.

Kerogen in region 9 may be treated to generate methane and hydrogen. Forexample, if such kerogen was previously treated (e.g., it was previouslyregion 7 kerogen), then after pyrolysis, longer hydrocarbon chains ofthe hydrocarbons may have already cracked and been. produced from theformation. Carbon and hydrogen, however, may still be present in theformation.

If kerogen in region 9 were heated to a synthesis gas generatingtemperature and a synthesis gas generating fluid (e.g., steam) wereadded to the region 9 kerogen, then at least a portion of remaininghydrocarbons in the formation may be produced from the formation in theform of synthesis gas. For region 9 kerogen, the atomic hydrogen tocarbon ratio and the atomic oxygen to carbon ratio in the hydrocarbonsmay significantly decrease as the temperature rises. In this manner,hydrocarbons in the formation may be transformed into relatively purecarbon in region 9. Heating region 9 kerogen to still highertemperatures will tend to transform such kerogen into graphite 11.

A hydrocarbon containing formation may have a number of properties thatwill depend on, for example, a composition of at least some of thehydrocarbons within the formation. Such properties tend to affect thecomposition and amount of products that are produced from a hydrocarboncontaining formation. Therefore, properties of a hydrocarbon containingformation can be used to determine if and/or how a hydrocarboncontaining formation could optimally be treated.

Kerogen is composed of organic matter that has been transformed due to amaturation process. Hydrocarbon containing formations that includekerogen may include, but are not limited to, coal formations and oilshale formations. Examples of hydrocarbon containing formations that maynot include kerogen are formations containing heavy hydrocarbons (e.g.,tar sands). The maturation process may include two stages: a biochemicalstage and a geochemical stage. The biochemical stage typically involvesdegradation of organic material by both aerobic and anaerobic organisms.The geochemical stage typically involves conversion of organic matterdue to temperature changes and significant pressures. During maturation,oil and gas may be produced as the organic matter of the kerogen istransformed.

The van Krevelen diagram shown in FIG. 2 classifies various naturaldeposits of kerogen. For example, kerogen may be classified into fourdistinct groups: type I, type II, type III, and type IV, which areillustrated by the four branches of the van Krevelen diagram. Thisdrawing shows the maturation sequence for kerogen, which typicallyoccurs over geological time due to temperature and pressure. The typesdepend upon precursor materials of the kerogen. The precursor materialstransform over time into macerals, which are microscopic structures thathave different structures and properties based on the precursormaterials from which they are derived. Oil shale may be described as akerogen type I or type II and may primarily contain macerals from theliptinite group. Liptinites are derived from plants, specifically thelipid rich and resinous parts. The concentration of hydrogen withinliptinite may be as high as 9 weight %. In addition, liptinite has arelatively high hydrogen to carbon ratio and a relatively low atomicoxygen to carbon ratio. A type I kerogen may also be further classifiedas an alginite, since type I kerogen may include primarily algal bodies.Type I kerogen may result from deposits made in lacustrine environments.Type II kerogen may develop from organic matter that was deposited inmarine environments.

Type III kerogen may generally include vitrinite macerals. Vitrinite isderived from cell walls and/or woody tissues (e.g., stems, branches,leaves and roots of plants). Type III kerogen may be present in mosthumic coals. Type III kerogen may develop from organic matter that wasdeposited in swamps. Type IV kerogen includes the inertinite maceralgroup. This group is composed of plant material such as leaves, bark andstems that have undergone oxidation during the early peat stages ofburial diagenesis. It is chemically similar to vitrinite but has a highcarbon and low hydrogen content. Thus, it is considered inert.

The dashed lines in FIG. 2 correspond to vitrinite reflectance. Thevitrinite reflectance is a measure of maturation. As kerogen undergoesmaturation, the composition of the kerogen usually changes. For example,as kerogen undergoes maturation, volatile matter of kerogen tends todecrease. Rank classifications of kerogen indicate the level to whichkerogen has matured. For example, as kerogen undergoes maturation, therank of kerogen increases. Therefore, as rank increases, the volatilematter of kerogen tends to decrease. In addition, the moisture contentof kerogen generally decreases as the rank increases. At higher ranks,however, the moisture content may become relatively constant. Forexample, higher rank kerogens that have undergone significantmaturation, such as semi-anthracite or anthracite coal, tend to have ahigher carbon content and a lower volatile matter content than lowerrank kerogens such as lignite. For example, rank stages of coalformations include the following classifications, which are listed inorder of increasing rank and maturity for type III kerogen: wood, peat,lignite, sub-bituminous coal, high volatile bituminous coal, mediumvolatile bituminous coal, low volatile bituminous coal, semi-anthracite,and anthracite. In addition, as rank increases, kerogen tends to exhibitan increase in aromatic nature.

Hydrocarbon containing formations may be selected for in situ treatmentbased on properties of at least a portion of the formation. For example,a formation may be selected based on richness, thickness, and depth(i.e., thickness of overburden) of the formation. In addition, aformation may be selected that will have relatively high quality fluidsproduced from the formation. In certain embodiments the quality of thefluids to be produced may be assessed in advance of treatment, therebygenerating significant cost savings since only more optimal formationswill be selected for treatment. Properties that may be used to assesshydrocarbons in a formation include, but are not limited to, an amountof hydrocarbon liquids that tend to be produced from the hydrocarbons, alikely API gravity of the produced hydrocarbon liquids, an amount ofhydrocarbon gas that tends to be produced from the hydrocarbons, and/oran amount of carbon dioxide and water that tend to be produced from thehydrocarbons.

Another property that may be used to assess the quality of fluidsproduced from certain kerogen containing formations is vitrinitereflectance. Such formations include, but are not limited to, coalformations and oil shale formations. Hydrocarbon containing formationsthat include kerogen can typically be assessed/selected for treatmentbased on a vitrinite reflectance of the kerogen. Vitrinite reflectanceis often related to a hydrogen to carbon atomic ratio of a kerogen andan oxygen to carbon atomic ratio of the kerogen, as shown by the dashedlines in FIG. 2. For example, a van Krevelen diagram may be useful inselecting a resource for an in situ conversion process.

Vitrinite reflectance of a kerogen in a hydrocarbon containing formationtends to indicate which fluids may be produced from a formation uponheating. For example, a vitrinite reflectance of approximately 0.5% toapproximately 1.5% tends to indicate a kerogen that, upon heating, willproduce fluids as described in region 7 above. Therefore, if ahydrocarbon containing formation having such kerogen is heated, asignificant amount (e.g., majority) of the fluid produced by suchheating will often include oil and other such hydrocarbon fluids. Inaddition, a vitrinite reflectance of approximately 1.5% to 3.0% mayindicate a kerogen in region 9 as described above. If a hydrocarboncontaining formation having such kerogen is heated, a significant amount(e.g., majority) of the fluid produced by such heating may includemethane and hydrogen (and synthesis gas, if, for example, thetemperature is sufficiently high and steam is injected). In anembodiment, at least a portion of a hydrocarbon containing formationselected for treatment in situ has a vitrinite reflectance in a rangebetween about 0.2% and about 3.0%. Alternatively, at least a portion ofa hydrocarbon containing formation selected for treatment has avitrinite reflectance from about 0.5% to about 2.0%, and, in somecircumstances, the vitrinite reflectance may range from about 0.5% to1.0%. Such ranges of vitrinite reflectance tend to indicate thatrelatively higher quality formation fluids will be produced from theformation.

In an embodiment, a hydrocarbon containing formation may be selected fortreatment based on a hydrogen content within the hydrocarbons in theformation. For example, a method of treating a hydrocarbon containingformation may include selecting a portion of the hydrocarbon containingformation for treatment having hydrocarbons with a hydrogen contentgreater than about 3 weight %, 3.5 weight %, or 4 weight % when measuredon a dry, ash-free basis. In addition, a selected section of ahydrocarbon containing formation may include hydrocarbons with an atomichydrogen to carbon ratio that falls within a range from about 0.5 toabout 2, and in many instances from about 0.70 to about 1.65.

Hydrogen content of a hydrocarbon containing formation may significantlyaffect a composition of hydrocarbon fluids produced from a formation.For example, pyrolysis of at least some of the hydrocarbons within theheated portion may generate hydrocarbon fluids that may include a doublebond or a radical. Hydrogen within the formation may reduce the doublebond to a single bond. In this manner, reaction of generated hydrocarbonfluids with each other and/or with additional components in theformation may be substantially inhibited. For example, reduction of adouble bond of the generated hydrocarbon fluids to a single bond mayreduce polymerization of the generated hydrocarbons. Such polymerizationtends to reduce the amount of fluids produced.

In addition, hydrogen within the formation may also neutralize radicalsin the generated hydrocarbon fluids. In this manner, hydrogen present inthe formation may substantially inhibit reaction of hydrocarbonfragments by transforming the hydrocarbon fragments into relativelyshort chain hydrocarbon fluids. The hydrocarbon fluids may enter a vaporphase and may be produced from the formation. The increase in thehydrocarbon fluids in the vapor phase may significantly reduce apotential for producing less desirable products within the selectedsection of the formation.

It is believed that if too little hydrogen is present in the formation,then the amount and quality of the produced fluids will be negativelyaffected. If too little hydrogen is naturally present, then in someembodiments hydrogen or other reducing fluids may be added to theformation.

When heating a portion of a hydrocarbon containing formation, oxygenwithin the portion may form carbon dioxide. It may be desirable toreduce the production of carbon dioxide and other oxides. In anembodiment, production of carbon dioxide may be reduced by selecting andtreating a portion of a hydrocarbon containing formation having avitrinite reflectance of greater than about 0.5%. In addition, an amountof carbon dioxide produced from a formation may vary depending on, forexample, an oxygen content of a treated portion of the hydrocarboncontaining formation. Certain embodiments may thus include selecting andtreating a portion of the formation having a kerogen with an atomicoxygen weight percentage of less than about 20%, 15%, and/or 10%. Inaddition, certain embodiments may include selecting and processing aformation containing kerogen with an atomic oxygen to carbon ratio ofless than about 0.15. Alternatively, at least some of the hydrocarbonsin a portion of a formation selected for treatment may have an atomicoxygen to carbon ratio of about 0.03 to about 0.12. In this manner,production of carbon dioxide and other oxides from an in situ conversionprocess for hydrocarbons may be reduced.

Heating a hydrocarbon containing formation may include providing a largeamount of energy to heat sources located within the formation.Hydrocarbon containing formations may contain water. Water present inthe hydrocarbon containing formation will tend to further increase theamount of energy required to heat a hydrocarbon containing formation. Inthis manner, water tends to hinder efficient heating of the formation.For example, a large amount of energy may be required to evaporate waterfrom a hydrocarbon containing formation. Thus, an initial rate oftemperature increase may be reduced by the presence of water in theformation. Therefore, excessive amounts of heat and/or time may berequired to heat a formation having a high moisture content to atemperature sufficient to allow pyrolysis of at least some of thehydrocarbons in the formation. In an embodiment, an in situ conversionprocess for hydrocarbons may include selecting a portion of thehydrocarbon containing formation for treatment having an initialmoisture content of less than about 15% by weight (in some embodimentsdewatering wells may be used to reduce the water content of theformation). Alternatively, an in situ conversion process forhydrocarbons may include selecting a portion of the hydrocarboncontaining formation for treatment having an initial moisture content ofless than about 10% by weight.

In an embodiment, a hydrocarbon containing formation may be selected fortreatment based on additional factors such as a thickness of hydrocarboncontaining layer within the formation and assessed liquid productioncontent. For example, a hydrocarbon containing formation may includemultiple layers. Such layers may include hydrocarbon containing layers,and also layers that may be hydrocarbon free or have substantially lowamounts of hydrocarbons. Each of the hydrocarbon containing layers mayhave a thickness that may vary depending on, for example, conditionsunder which the hydrocarbon containing layer was formed. Therefore, ahydrocarbon containing formation will typically be selected fortreatment if that formation includes at least one hydrocarbon containinglayer having a thickness sufficient for economical production offormation fluids. A formation may also be chosen if the thickness ofseveral layers that are closely spaced together is sufficient foreconomical production of formation fluids. Other formations may also bechosen based on a richness of the hydrocarbon resource within the soil,even if the thickness of the resource is relatively thin.

In addition, a layer of a hydrocarbon containing formation may beselected for treatment based on a thickness of the hydrocarboncontaining layer, and/or a total thickness of hydrocarbon containinglayers in a formation. For example, an in situ conversion process forhydrocarbons may include selecting and treating a layer of a hydrocarboncontaining formation having a thickness of greater than about 2 m, 3 m,and/or 5 m. In this manner, heat losses (as a fraction of total injectedheat) to layers formed above and below a layer of hydrocarbons may beless than such heat losses from a thin layer of hydrocarbons. A processas described herein, however, may also include selecting and treatinglayers that may include layers substantially free of hydrocarbons andthin layers of hydrocarbons.

Each of the hydrocarbon containing layers may also have a potentialformation fluid yield that may vary depending on, for example,conditions under which the hydrocarbon containing layer was formed, anamount of hydrocarbons in the layer, and/or a composition ofhydrocarbons in the layer. A potential formation fluid yield may bemeasured, for example, by the Fischer Assay. The Fischer Assay is astandard method which involves heating a sample of a hydrocarboncontaining layer to approximately 500° C. in one hour, collectingproducts produced from the heated sample, and quantifying the amount ofproducts produced. A sample of a hydrocarbon containing layer may beobtained from a hydrocarbon containing formation by a method such ascoring or any other sample retrieval method.

FIG. 3 shows a schematic view of an embodiment of a portion of an insitu conversion system for treating a hydrocarbon containing formation.Heat sources 100 may be placed within at least a portion of thehydrocarbon containing formation. Heat sources 100 may include, forexample, electrical heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 100 mayalso include other types of heaters. Heat sources 100 are configured toprovide heat to at least a portion of a hydrocarbon containingformation. Energy may be supplied to the heat sources 100 through supplylines 102. The supply lines may be structurally different depending onthe type of heat source or heat sources being used to heat theformation. Supply lines for heat sources may transmit electricity forelectrical heaters, may transport fuel for combustors, or may transportheat exchange fluid that is circulated within the formation.

Production wells 104 may be used to remove formation fluid from theformation. Formation fluid produced from the production wells 104 may betransported through collection piping 106 to treatment facilities 108.Formation fluids may also be produced from heat sources 100. Forexample, fluid.may be produced from heat sources 100 to control pressurewithin the formation adjacent to the heat sources. Fluid produced fromheat sources 100 may be transported through tubing or piping to thecollection piping 106 or the produced fluid may be transported throughtubing or piping directly to the treatment facilities 108. The treatmentfacilities 108 may include separation units, reaction units, upgradingunits, fuel cells, turbines, storage vessels, and other systems andunits for processing produced formation fluids.

An in situ conversion system for treating hydrocarbons may includedewatering wells 110 (wells shown with reference number 110 may, in someembodiments, be capture and/or isolation wells). Dewatering wells 110 orvacuum wells may be configured to remove and inhibit liquid water fromentering a portion of a hydrocarbon containing formation to be heated,or to a formation being heated. A plurality of water wells may surroundall or a portion of a formation to be heated. In the embodiment depictedin FIG. 3, the dewatering wells 110 are shown extending only along oneside of heat sources 100, but dewatering wells typically encircle allheat sources 100 used, or to be used, to heat the formation.

Dewatering wells 110 may be placed in one or more rings surroundingselected portions of the formation. New dewatering wells may need to beinstalled as an area being treated by the in situ conversion processexpands. An outermost row of dewatering wells may inhibit a significantamount of water from flowing into the portion of formation that isheated or to be 7 heated. Water produced from the outermost row ofdewatering wells should be substantially clean, and may require littleor no treatment before being released. An innermost row of dewateringwells may inhibit water that bypasses the outermost row from flowinginto the portion of formation that is heated or to be heated. Theinnermost row of dewatering wells may also inhibit outward migration ofvapor from a heated portion of the formation into surrounding portionsof the formation. Water produced by the innermost row of dewateringwells may include some hydrocarbons. The water may need to be treatedbefore being released. Alternately, water with hydrocarbons may bestored and used to produce synthesis gas from a portion of the formationduring a synthesis gas phase of the in situ conversion process. Thedewatering wells may reduce heat loss to surrounding portions of theformation, may increase production of vapors from the heated portion,and may inhibit contamination of a water table proximate the heatedportion of the formation.

In an alternative embodiment, a fluid (e.g., liquid or gas) may beinjected in the innermost row of wells, allowing a selected pressure tobe maintained in or about the pyrolysis zone. Additionally, this fluidmay act as an isolation barrier between the outermost wells and thepyrolysis fluids, thereby improving the efficiency of the dewateringwells.

The hydrocarbons to be treated may be located under a large area. The insitu conversion system may be used to treat small portions of theformation, and other sections of the formation may be treated as timeprogresses. In an embodiment of a system for treating an oil shaleformation, a field layout for 24 years of development may be dividedinto 24 individual plots that represent individual drilling years. Eachplot may include 120 “tiles” (repeating matrix patterns) wherein eachtile is made of 6 rows by 20 columns. Each tile may include 1 productionwell and 12 or 18 heater wells. The heater wells may be placed in anequilateral triangle pattern with, for example, a well spacing of about12 m. Production wells may be located in centers of equilateraltriangles of heater wells, or the production wells may be locatedapproximately at a midpoint between two adjacent heater wells.

In certain embodiments, heat sources will be placed within a heater wellformed within a hydrocarbon containing formation. The heater well mayinclude an opening through an overburden of the formation and into atleast one hydrocarbon containing section of the formation.Alternatively, as shown in FIG. 3a, heater well 224 may include anopening in formation 222 that may have a shape substantially similar toa helix or spiral. A spiral configuration for a heater well may in someembodiments increase the transfer of heat from the heat source and/orallow the heat source to expand when heated, without buckling or othermodes of failure. In some embodiments, such a heater well may alsoinclude a substantially straight section through overburden 220. Use ofa straight heater well through the overburden may decrease heat loss tothe overburden.

In an alternative embodiment, as shown in FIG. 3b, heat sources may beplaced into heater well 224 that may include an opening in formation 222having a shape substantially similar to a “U” (the “legs” of the “U” maybe wider or more narrow depending on the embodiments used). Firstportion 226 and third portion 228 of heater well 224 may be arrangedsubstantially perpendicular to an upper surface of formation 222. Inaddition, the first and the third portion of the heater well may extendsubstantially vertically through overburden 220. Second portion 230 ofheater well 224 may be substantially parallel to the upper surface ofthe formation.

In addition, multiple heat sources (e.g., 2, 3, 4, 5, 10 heat sources ormore) may extend from a heater well in some situations. For example, asshown in FIG. 3c, heat sources 232, 234, and 236 may extend throughoverburden 220 into formation 222 from heater well 224. Such situationsmay occur when surface considerations (e.g., aesthetics, surface landuse concerns, and/or unfavorable soil conditions near the surface) makeit desirable to concentrate the surface facilities in fewer locations.For example, in areas where the soil is frozen and/or marshy it may bemore cost-effective to have surface facilities located in a morecentralized location.

In certain embodiments a first portion of a heater well may extend froma surface of the Aground, through an overburden, and into a hydrocarboncontaining formation. A second portion of the heater well may includeone or more heater wells in the hydrocarbon containing formation. Theone or more heater wells may be disposed within the hydrocarboncontaining formation at various angles. In some embodiments, at leastone of the heater wells may be disposed substantially parallel to aboundary of the hydrocarbon containing formation. In alternateembodiments, at least one of the heater wells may be substantiallyperpendicular to the hydrocarbon containing formation. In addition, oneof the one or more heater wells may be positioned at an angle betweenperpendicular and parallel to a layer in the formation.

FIG. 4 illustrates an embodiment of a hydrocarbon containing formation200 that may be at a substantially near-horizontal angle with respect toan upper surface of the ground 204. An angle of hydrocarbon containingformation 200, however, may vary. For example, hydrocarbon containingformation 200 may be steeply dipping. Economically viable production ofa steeply dipping hydrocarbon containing formation may not be possibleusing presently available mining methods. A relatively steeply dippinghydrocarbon containing formation, however, may be subjected to an insitu conversion process as described herein. For example, a single setof gas producing wells may be disposed near a top of a steeply dippinghydrocarbon containing formation. Such a formation may be heated byheating a portion of the formation proximate a top of the hydrocarboncontaining formation and sequentially heating lower sections of thehydrocarbon containing formation. Gases may be produced from thehydrocarbon containing formation by transporting gases through thepreviously pyrolyzed hydrocarbons with minimal pressure loss.

In an embodiment, an in situ conversion process for hydrocarbons mayinclude providing heat to at least a portion of a hydrocarbon containingformation that dips in sections. For example, a portion of the formationmay include a dip that may include a minimum depth of the portion. Aproduction well may be located in the portion of the hydrocarboncontaining formation proximate the minimum depth. An additionalproduction well may not be required in the portion. For example, as heattransfers through the hydrocarbon containing formation and at least somehydrocarbons in the portion pyrolyze, pyrolyzation fluids formed in theportion may travel through pyrolyzed sections of the hydrocarboncontaining formation to the production well. As described herein,increased permeability due to in situ treatment of a hydrocarboncontaining formation may increase transfer of vapors through the treatedportion of the formation. Therefore, a number of production wellsrequired to produce a mixture from the formation may be reduced.Reducing the number of production wells required for production mayincrease economic viability of an in situ conversion process.

In steeply dipping formations, directional drilling may be used to forman opening for a heater well in the formation. Directional drilling mayinclude drilling an opening in which the route/course of the opening maybe planned before drilling. Such an opening may usually be drilled withrotary equipment. In directional drilling, a route/course of an openingmay be controlled by deflection wedges, etc.

Drilling heater well 202 may also include drilling an opening in theformation with a drill equipped with a steerable motor and anaccelerometer that may be configured to follow hydrocarbon containingformation 200. For example, a steerable motor may be configured tomaintain a substantially constant distance between heater well 202 and aboundary of hydrocarbon containing formation 200 throughout drilling ofthe opening. Drilling of heater well 202 with the steerable motor andthe accelerometer may be relatively economical.

Alternatively, geosteered drilling may be used to drill heater well 202into hydrocarbon containing formation 200. Geosteered drilling mayinclude determining or estimating a distance from an edge of hydrocarboncontaining formation 200 to heater well 202 with a sensor. The sensormay include, but may not be limited to, sensors that may be configuredto determine a distance from an edge of hydrocarbon containing formation200 to heater well 202. In addition, such a sensor may be configured todetermine and monitor a variation in a characteristic of the hydrocarboncontaining formation 200. Such sensors may include, but may not belimited to, sensors that may be configured to measure a characteristicof a hydrocarbon seam using resistance, gamma rays, acoustic pulses,and/or other devices. Geosteered drilling may also include forming anopening for a heater well with a drilling apparatus that may include asteerable motor. The motor may be controlled to maintain a predetermineddistance from an edge of a hydrocarbon containing formation. In anadditional embodiment, drilling of a heater well or any other well in aformation may also include sonic drilling.

FIG. 5 illustrates an embodiment of a plurality of heater wells 210formed in hydrocarbon containing formation 212. Hydrocarbon containingformation 212 may be a steeply dipping formation. One or more of theheater wells 210 may be formed in the formation such that two or more ofthe heater wells are substantially parallel to each other, and/or suchthat at least one heater well is substantially parallel to hydrocarboncontaining formation 212. For example, one or more of the heater wells210 may be formed in hydrocarbon containing formation 212 by a magneticsteering method. An example of a magnetic steering method is illustratedin U.S. Pat. No. 5,676,212 to Kuckes, which is incorporated by referenceas if fully set forth herein. Magnetic steering may include drillingheater well 210 parallel to an adjacent heater well. The adjacent wellmay have been previously drilled. In addition, magnetic steering mayinclude directing the drilling by sensing and/or determining a magneticfield produced in an adjacent heater well. For example, the magneticfield may be produced in the adjacent heater well by flowing a currentthrough an insulated current-carrying wireline disposed in the adjacentheater well. Alternatively, one or more of the heater wells 210 may beformed by a method as is otherwise described herein. A spacing betweenheater wells 210 may be determined according to any of the embodimentsdescribed herein.

In some embodiments, heated portion 310 may extend substantiallyradially from heat source 300, as shown in FIG. 6. For example, a widthof heated portion 310, in a direction extending radially from heatsource 300, may be about 0 m to about 10 m . A width of heated portion310 may vary, however, depending upon, for example, heat provided byheat source 300 and the characteristics of the formation. Heat providedby heat source 300 will typically transfer through the heated portion tocreate a temperature gradient within the heated portion. For example, atemperature proximate the heater well will generally be higher than atemperature proximate an outer lateral boundary of the heated portion. Atemperature gradient within the heated portion, however, may vary withinthe heated portion depending on, for example, the thermal conductivityof the formation.

As heat transfers through heated portion 310 of the hydrocarboncontaining formation, a temperature within at least a section of theheated portion may be within a pyrolysis temperature range. In thismanner, as the heat transfers away from the heat source, a front atwhich pyrolysis occurs will in many instances travel outward from theheat source. For example, heat from the heat source may be allowed totransfer into a selected section of the heated portion such that heatfrom the heat source pyrolyzes at least some of the hydrocarbons withinthe selected section. As such, pyrolysis may occur within selectedsection 315 of the heated portion, and pyrolyzation fluids will begenerated from hydrocarbons in the selected section. An inner lateralboundary of selected section 315 may be radially spaced from the heatsource. For example, an inner lateral boundary of selected section 315may be radially spaced from the heat source by about 0 m to about 1 m.In addition, selected section 315 may have a width radially extendingfrom the inner lateral boundary of the selected section. For example, awidth of the selected section may be at least approximately 1.5 m, atleast approximately 2.4 m, or even at least approximately 3.0 m. A widthof the selected section, however, may also be greater than approximately1.5 m and less than approximately 10 m.

After pyrolyzation of hydrocarbons in a portion of the selected sectionis complete, a section of spent hydrocarbons 317 may be generatedproximate to the heat source.

In some embodiments, a plurality of heated portions may exist within aunit of heat sources. A unit of heat sources refers to a minimal numberof heat sources that form a template that may be repeated to create apattern of heat sources within the formation. The heat sources may belocated within the formation such that superposition (overlapping) ofheat produced from the heat sources is effective. For example, asillustrated in FIG. 7, transfer of heat from two or more heat sources330 results in superposition of heat 332 to be effective within an areadefined by the unit of heat sources. Superposition may also be effectivewithin an interior of a region defined by two, three, four, five, six,or more heat sources. For example, an area in which superposition ofheat 332 is effective includes an area to which significant heat istransferred by two or more heat sources of the unit of heat sources. Anarea in which superposition of heat is effective may vary dependingupon, for example, the spacings between heat sources.

Superposition of heat may increase a temperature in at least a portionof the formation to a temperature sufficient for pyrolysis ofhydrocarbon within the portion. In this manner, superposition of heat332 tends to increase the amount of hydrocarbons in a formation that maybe pyrolyzed. As such, a plurality of areas that are within a pyrolysistemperature range may exist within the unit of heat sources. Theselected sections 334 may include areas in a pyrolysis temperature rangedue to heat transfer from only one heat source, as well as areas in apyrolysis temperature range due to superposition of heat.

In addition, a pattern of heat sources will often include a plurality ofunits of heat sources. There will typically be a plurality of heatedportions, as well as selected sections within the pattern of heatsources. The plurality of heated portions and selected sections may beconfigured as described herein. Superposition of heat within a patternof heat sources may decrease the time necessary to reach pyrolysistemperatures within the multitude of heated portions. Superposition ofheat may allow for a relatively large spacing between adjacent heatsources, which may in turn provide a relatively slow rate of heating ofthe hydrocarbon containing formation. In certain embodiments,superposition of heat will also generate fluids substantially uniformlyfrom a heated portion of a hydrocarbon containing formation.

In certain embodiments, a majority of pyrolysis fluids may be producedwhen the selected section is within a range from about 0 m to about 25 mfrom a heat source.

As shown in FIG. 3, in addition to heat sources 100, one or moreproduction wells 104 will typically be disposed within the portion ofthe coal formation. Formation fluids may be produced through productionwell 104. Production well 104 may also include a heat source. In thismanner, the formation fluids may be maintained at a selected temperaturethroughout production, thereby allowing more or all of the formationfluids to be produced as vapors. Therefore, high temperature pumping ofliquids from the production well may be reduced or substantiallyeliminated, which in turn decreases production costs. Providing heatingat or through the production well tends to: (1) inhibit condensationand/or refluxing of production fluid when such production fluid ismoving in the production well proximate to the overburden, (2) increaseheat input into the formation, and/or (3) increase formationpermeability at or proximate the production well.

Because permeability and/or porosity increases in the heated formation,produced vapors may flow considerable distances through the formationwith relatively little pressure differential. Therefore, in someembodiments, production wells may be provided near an upper surface ofthe formation. Increases in permeability may result from a reduction ofmass of the heated portion due to vaporization of water, removal ofhydrocarbons, and/or creation of fractures. In this manner, fluids maymore easily flow through the heated portion.

For example, fluid generated within a hydrocarbon containing formationmay move a considerable distance through the hydrocarbon containingformation as a vapor. Such a considerable distance may include, forexample, about 50 m to about 1000 m. The vapor may have a relativelysmall pressure drop across the considerable distance due to thepermeability of the heated portion of the formation. In addition, due tosuch permeability, a production well may only need to be provided inevery other unit of heat sources or every third, fourth, fifth, sixthunits of heat sources. Furthermore, as shown in FIG. 4, production wells206 may extend through a hydrocarbon containing formation near the topof heated portion 208.

Embodiments of production well 102 may include valves configured toalter, maintain, and/or control a pressure of at least a portion of theformation. Production wells may be cased wells that may have productionscreens or perforated casings adjacent to production zones. In addition,the production wells may be surrounded by sand, gravel or other packingmaterial adjacent to production zones. Furthermore, production wells 102may be coupled to treatment section 108, as shown in FIG. 3. Treatmentsection 108 may include any of the surface facilities as describedherein.

In addition, water pumping wells or vacuum wells may be configured toremove liquid water from a portion of a hydrocarbon containing formationto be heated. Water removed from the formation may be used on thesurface, and/or monitored for water quality. For example, a plurality ofwater wells may surround all or a portion of a formation to be heated.The plurality of water wells may be configured in one or more ringssurrounding the portion of the formation. An outermost row of waterwells may inhibit a significant amount of water from flowing into theportion to be heated. An innermost row of water wells may inhibit waterthat bypasses the outermost row from flowing into the portion to beheated. The innermost row of water wells may also inhibit outwardmigration of vapor from a heated portion of the formation intosurrounding portions of the formation. In this manner, the water wellsmay reduce heat loss to surrounding portions of the formation, mayincrease production of vapors from the heated portion, and may inhibitcontamination of a water table proximate to the heated portion of theformation. In some embodiments pressure differences between successiverows of dewatering wells may be minimized (e.g., maintained or nearzero) to create a “no or low flow” boundary between rows.

In certain embodiments, wells initially used for one purpose may belater used for one or more other purposes, thereby lowering projectcosts and/or decreasing the time required to perform certain tasks. Forinstance, production wells (and in some circumstances heater wells) mayinitially be used as dewatering wells (e.g., before heating is begunand/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.), and monitoring wells may later be used for otherpurposes.

FIG. 8 illustrates a pattern of heat sources 400 and production wells402 that may be configured to treat a hydrocarbon containing formation.Heat sources 400 may be arranged in a unit of heat sources such astriangular pattern 401. Heat sources 400, however, may be arranged in avariety of patterns including, but not limited to, squares, hexagons,and other polygons. The pattern may include a regular polygon to promoteuniform heating through at least the portion of the formation in whichthe heat sources are placed. The pattern may also be a line drivepattern. A line drive pattern generally includes a first linear array ofheater wells, a second linear array of heater wells, and a productionwell or a linear array of production wells between the first and secondlinear array of heater wells.

A distance from a node of a polygon to a centroid of the polygon issmallest for a 3 sided polygon and increases with increasing number ofsides of the polygon. The distance from a node to the centroid for anequilateral triangle is (length/2)/(square root(3)/2) or 0.5774 timesthe length. For a square, the distance from a node to the centroid is(length/2)/(square root(2)/2) or 0.7071 times the length. For a hexagon,the distance from a node to the centroid is (length/2)/(½) or thelength. The difference in distance between a heat source and a midpointto a second heat source (length/2) and the distance from a heat sourceto the centroid for an equilateral pattern (0.5774 times the length) issignificantly less for the equilateral triangle pattern than for anyhigher order polygon pattern. The small difference means thatsuperposition of heat may develop more rapidly and that the formationbetween heat sources may rise to a substantially more uniformtemperature using an equilateral triangle pattern rather than a higherorder polygon pattern.

Triangular patterns tend to provide more uniform heating to a portion ofthe formation in comparison to other patterns such as squares and/orhexagons. Triangular patterns tend to provide faster heating to apredetermined temperature in comparison to other patterns such assquares and/or hexagons. Triangle patterns may also result in a smallvolume of the portion that is overheated. A plurality of units of heatsources such as triangular pattern 401 may be arranged substantiallyadjacent to each other to form a repetitive pattern of units over anarea of the formation. For example, triangular patterns 401 may bearranged substantially adjacent to each other in a repetitive pattern ofunits by inverting an orientation of adjacent triangles 401. Otherpatterns of heat sources 400 may also be arranged such that smallerpatterns may be disposed adjacent to each other to form larger patterns.

Production wells may be disposed in the formation in a repetitivepattern of units. In certain embodiments, production well 402 may bedisposed proximate to a center of every third triangle 401 arranged inthe pattern. Production well 402, however, may be disposed in everytriangle 401 or within just a few triangles. A production well may beplaced within every 13, 20, or 30 heater well triangles. For example, aratio of heat sources in the repetitive pattern of units to productionwells in the repetitive pattern of units may be more than approximately5 (e.g., more than 6, 7, 8, or 9). In addition, the placement ofproduction well 402 may vary depending on the heat generated by one ormore heat sources 400 and the characteristics of the formation (such aspermeability). Furthermore, three or more production wells may belocated within an area defined by a repetitive pattern of units. Forexample, as shown in FIG. 8, production wells 410 may be located withinan area defined by repetitive pattern of units 412. Production wells 410may be located in the formation in a unit of production wells. Forexample, the unit of production wells may be a triangular pattern.Production wells 410, however, may be disposed in another pattern withinrepetitive pattern of units 412.

In addition, one or more injection wells may be disposed within arepetitive pattern of units. The injection wells may be configured asdescribed herein. For example, as shown in FIG. 8, injection wells 414may be located within an area defined by repetitive pattern of units416. Injection wells 414 may also be located in the formation in a unitof injection wells. For example, the unit of injection wells may be atriangular pattern. Injection wells 414, however, may be disposed in anyother pattern as described herein. In certain embodiments, one or moreproduction wells and one or more injection wells may be disposed in arepetitive pattern of units. For example, as shown in FIG. 8, productionwells 418 and injection wells 420 may be located within an area definedby repetitive pattern of units 422. Production wells 418 may be locatedin the formation in a unit of production wells, which may be arranged ina first triangular pattern. In addition, injection wells 420 may belocated within the formation in a unit of production wells, which may bearranged in a second triangular pattern. The first triangular patternmay be substantially different than the second triangular pattern. Forexample, areas defined by the first and second triangular patterns maybe substantially different.

In addition, one or more monitoring wells may be disposed within arepetitive pattern of units. The monitoring wells may be configured asdescribed herein. For example, the wells may be configured with one ormore devices that measure a temperature, a pressure, and/or a propertyof a fluid. In some embodiments, logging tools may be placed inmonitoring well wellbores to measure properties within a formation. Thelogging tools may be moved to other monitoring well wellbores as needed.The monitoring well wellbores may be cased or uncased wellbores. Asshown in FIG. 8, monitoring wells 424 may be located within an areadefined by repetitive pattern of units 426. Monitoring wells 424 may belocated in the formation in a unit of monitoring wells, which may bearranged in a triangular pattern. Monitoring wells 424, however, may bedisposed in any of the other patterns as described herein withinrepetitive pattern of units 426.

It is to be understood that a geometrical pattern of heat sources 400and production wells 402 is described herein by example. A pattern ofheat sources and production wells will in many instances vary dependingon, for example, the type of hydrocarbon containing formation to betreated. For example, for relatively thin layers heating wells may bealigned along one or more layers along strike or along dip. Forrelatively thick layers, heat sources may be configured at an angle toone or more layers (e.g., orthogonally or diagonally).

A triangular pattern of heat sources may be configured to treat ahydrocarbon containing formation having a thickness of about 10 metersor more. For a thinner hydrocarbon containing formation, e.g., about 10meters thick or less, a line and/or staggered line pattern of heatsources may be configured to treat the hydrocarbon containing formation.

For certain thinner formations, heating wells may be placed closer to anedge of the formation (e.g., in a staggered line instead of a lineplaced in the center of the layer) of the to formation to increase theamount of hydrocarbons produced per unit of energy input. A portion ofinput heating energy may heat non-hydrocarbon containing formation, butthe staggered pattern may allow superposition of heat to heat a majorityof the hydrocarbon formation to pyrolysis temperatures. If the thinformation is heated by placing one or more heater wells in the formationalong a center of the thickness, a significant portion of thehydrocarbon containing formation may not be heated to pyrolysistemperatures. In some embodiments, placing heater wells closer to anedge of the formation may increase the volume of formation undergoingpyrolysis per unit of energy input.

In addition, the location of production well 402 within a pattern ofheat sources 400 may be determined by, for example, a desired heatingrate of the hydrocarbon containing formation, a heating rate of the heatsources, the type of heat sources used, the type of hydrocarboncontaining formation (and its thickness), the composition of thehydrocarbon containing formation, the desired composition to be producedfrom the formation, and/or a desired production rate. Exact placement ofheater wells, production wells, etc. will depend on variables specificto the formation (e.g., thickness of the layer, composition of thelayer, etc.), project economics, etc. In certain embodiments heaterwells may be substantially horizontal while production wells may bevertical, or vice versa.

Any of the wells described herein may be aligned along dip or strike, ororiented at an angle between dip and strike.

The spacing between heat sources may also vary depending on a number offactors that may include, but are not limited to, the type of ahydrocarbon containing formation, the selected heating rate, and/or theselected average temperature to be obtained within the heated portion.For example, the spacing between heat sources may be within a range ofabout 5 m to about 25 m. Alternatively, the spacing between heat sourcesmay be within a range of about 8 m to about 15 m.

The spacing between heat sources may influence the composition of fluidsproduced from a hydrocarbon containing formation. In an embodiment, acomputer-implemented method may be used to determine optimum heat sourcespacings within a hydrocarbon containing formation. For example, atleast one property of a portion of hydrocarbon containing formation canusually be measured. The measured property may include, but is notlimited to, vitrinite reflectance, hydrogen content, atomic hydrogen tocarbon ratio, oxygen content, atomic oxygen to carbon ratio, watercontent, thickness of the hydrocarbon containing formation, and/or theamount of stratification of the hydrocarbon containing formation intoseparate layers of rock and hydrocarbons.

In certain embodiments a computer-implemented method may includeproviding at least one measured property to a computer system. One ormore sets of heat source spacings in the formation may also be providedto the computer system. For example, a spacing between heat sources maybe less than about 30 m. Alternatively, a spacing between heat sourcesmay be less than about 15 m. The method may also include determiningproperties of fluids produced from the portion as a function of time foreach set of heat source spacings. The produced fluids include, but arenot limited to, formation fluids such as pyrolyzation fluids andsynthesis gas. The determined properties may include, but are notlimited to, API gravity, carbon number distribution, olefin content,hydrogen content, carbon monoxide content, and/or carbon dioxidecontent. The determined set of properties of the produced fluid may becompared to a set of selected properties of a produced fluid. In thismanner, sets of properties that match the set of selected properties maybe determined. Furthermore, heat source spacings may be matched to heatsource spacings associated with desired properties.

Unit cell 404 will often include a number of heat sources 400 disposedwithin a formation around each production well 402. An area of unit cell404 may be determined by midlines 406 that may be equidistant andperpendicular to a line connecting two production wells 402. Vertices408 of the unit cell may be at the intersection of two midlines 406between production wells 402. Heat sources 400 may be disposed in anyarrangement within the area of unit cell 404. For example, heat sources400 may be located within the formation such that a distance betweeneach heat source varies by less than approximately 10%, 20%, or 30%. Inaddition, heat sources 400 may be disposed such that an approximatelyequal space exists between each of the heat sources. Other arrangementsof heat sources 400 within unit cell 404, however, may be used dependingon, for example, a heating rate of each of the heat sources. A ratio ofheat sources 400 to production wells 402 may be determined by countingthe number of heat sources 400 and production wells 402 within unit cell404, or over the total field.

FIG. 9 illustrates an embodiment of unit cell 404. Unit cell 404includes heat sources 400 and production wells 402. Unit cell 404 mayhave six full heat sources 400 a and six partial heat sources 400 b.Full heat sources 400 a may be closer to production well 402 thanpartial heat sources 400 b. In addition, an entirety of each of the fullheat sources 400 a may be located within unit cell 404. Partial heatsources 400 b may be partially disposed within unit cell 404. Only aportion of heat source 400 b disposed within unit cell 404 may beconfigured to provide heat to a portion of a hydrocarbon containingformation disposed within unit cell 404. A remaining portion of heatsource 400 b disposed outside of unit cell 404 may be configured toprovide heat to a remaining portion of the hydrocarbon containingformation outside of unit cell 404. Therefore, to determine a number ofheat sources within unit cell 404 partial heat source 400 b may becounted as one-half of full heat source 400 a. In other unit cellembodiments, fractions other than ½ (e.g. ⅓) may more accuratelydescribe the amount of heat applied to a portion from a partial heatsource.

The total number of heat sources 400 in unit cell 404 may include sixfull heat sources 400 a that are each counted as one heat source, andsix partial heat sources 400 b that are each counted as one half of aheat source. Therefore, a ratio of heat sources 400 to production wells402 in unit cell 404 may be determined as 9:1. A ratio of heat sourcesto production wells may vary, however, depending on, for example, thedesired heating rate of the hydrocarbon containing formation, theheating rate of the heat sources, the type of heat source, the type ofhydrocarbon containing formation, the composition of hydrocarboncontaining formation, the desired composition of the produced fluid,and/or the desired production rate. Providing more heat sources wellsper unit area will allow faster heating of the selected portion and thushastening the onset of production, however more heat sources willgenerally cost more money to install. An appropriate ratio of heatsources to production wells may also include ratios greater than about5:1, and ratios greater than about 7:1. In some embodiments anappropriate ratio of heat sources to production wells may be about 10:1,20:1, 50:1 or greater. If larger ratios are used, then project coststend to decrease since less wells and equipment are needed.

A “selected section” would generally be the volume of formation that iswithin a perimeter defined by the location of the outermost heat sources(assuming that the formation is viewed from above). For example, if fourheat sources were located in a single square pattern with an area ofabout 100 m² (with each source located at a corner of the square), andif the formation had an average thickness of approximately 5 m acrossthis area, then the selected section would be a volume of about 500 m³(i.e., the area multiplied by the average formation thickness across thearea). In many commercial applications, it is envisioned that many(e.g., hundreds or thousands) heat sources would be adjacent to eachother to heat a selected section, and therefore in such cases only theoutermost (i.e., the “edge”) heat sources would define the perimeter ofthe selected section.

A heat source may include, but is not limited to, an electric heater ora combustion heater. The electric heater may include an insulatedconductor, an elongated member disposed in the opening, and/or aconductor disposed in a conduit. Such an electric heater may beconfigured according to any of the embodiments described herein.

In an embodiment, a hydrocarbon containing formation may be heated witha natural distributed combustor system located in the formation. Thegenerated heat may be allowed to transfer to a selected section of theformation to heat it.

A temperature sufficient to support oxidation may be, for example, atleast about 200° C. or 250° C. The temperature sufficient to supportoxidation will tend to vary, however, depending on, for example, acomposition of the hydrocarbons in the hydrocarbon containing formation,water content of the formation, and/or type and amount of oxidant. Somewater may be removed from the formation prior to heating. For example,the water may be pumped from the formation by dewatering wells. Theheated portion of the formation may be near or substantially adjacent toan opening in the hydrocarbon containing formation. The opening in theformation may be a heater well formed in the formation. The heater wellmay be formed as in any of the embodiments described herein. The heatedportion of the hydrocarbon containing formation may extend radially fromthe opening to a width of about 0.3 m to about 1.2 m. The width,however, may also be less than about 0.9 m. A width of the heatedportion may vary. In certain embodiments the variance will depend on,for example, a width necessary to generate sufficient heat duringoxidation of carbon to maintain the oxidation reaction without providingheat from an additional heat source.

After the portion of the formation reaches a temperature sufficient tosupport oxidation, an oxidizing fluid may be provided into the openingto oxidize at least a portion of the hydrocarbons at a reaction zone, ora heat source zone, within the formation. Oxidation of the hydrocarbonswill generate heat at the reaction zone. The generated heat will in mostembodiments transfer from the reaction zone to a pyrolysis zone in theformation. In certain embodiments the generated heat will transfer at arate between about 650 watts per meter as measured along a depth of thereaction zone, and/or 1650 watts per meter as measured along a depth ofthe reaction zone. Upon oxidation of at least some of the hydrocarbonsin the formation, energy supplied to the heater for initially heatingmay be reduced or may be turned off. As such, energy input costs may besignificantly reduced, thereby providing a significantly more efficientsystem for heating the formation.

In an embodiment, a conduit may be disposed in the opening to providethe oxidizing fluid into the opening. The conduit may have floworifices, or other flow control mechanisms (i.e., slits, venturi meters,valves, etc.) to allow the oxidizing fluid to enter the opening. Theterm “orifices” includes openings having a wide variety ofcross-sectional shapes including, but not limited to, circles, ovals,squares, rectangles, triangles, slits, or other regular or irregularshapes. The flow orifices may be critical flow orifices in someembodiments. The flow orifices may be configured to provide asubstantially constant flow of oxidizing fluid into the opening,regardless of the pressure in the opening.

In some embodiments, the number of flow orifices, which may be formed inor coupled to the conduit, may be limited by the diameter of theorifices and a desired spacing between orifices for a length of theconduit. For example, as the diameter of the orifices decreases, thenumber of flow orifices may increase, and vice versa. In addition, asthe desired spacing increases, the number of flow orifices may decrease,and vice versa. The diameter of the orifices may be determined by, forexample, a pressure in the conduit and/or a desired flow rate throughthe orifices. For example, for a flow rate of about 1.7 standard cubicmeters per minute and a pressure of about 7 bar absolute, an orificediameter may be about 1.3 mm with a spacing between orifices of about 2m.

Smaller diameter orifices may plug more easily than larger diameterorifices due to, for example, contamination of fluid in the opening orsolid deposition within or proximate to the orifices. In someembodiments, the number and diameter of the orifices can be chosen suchthat a more even or nearly uniform heating profile will be obtainedalong a depth of the formation within the opening. For example, a depthof a heated formation that is intended to have an approximately uniformheating profile may be greater than about 300 m, or even greater thanabout 600 m. Such a depth may vary, however, depending on, for example,a type of formation to be heated and/or a desired production rate.

In some embodiments, flow orifices may be disposed in a helical patternaround the conduit within the opening. The flow orifices may be spacedby about 0.3 m to about 3 m between orifices in the helical pattern. Insome embodiments, the spacing may be about 1 m to about 2 m or, forexample, about 1.5 m.

The flow of the oxidizing fluid into the opening may be controlled suchthat a rate of oxidation at the reaction zone is controlled. Transfer ofheat between incoming oxidant and outgoing oxidation products may heatthe oxidizing fluid. The transfer of heat may also maintain the conduitbelow a maximum operating temperature of the conduit.

FIG. 10 illustrates an embodiment of a natural distributed combustorconfigured to heat a hydrocarbon containing formation. Conduit 512 maybe placed into opening 514 in formation 516. Conduit 512 may have innerconduit 513. Oxidizing fluid source 508 may provide oxidizing fluid 517into inner conduit 513. Inner conduit 513 may have critical floworifices 515 along its length. Critical flow orifices 515 may bedisposed in a helical pattern (or any other pattern) along a length ofinner conduit 513 in opening 514. For example, critical flow orifices515 may be arranged in a helical pattern with a distance of about 1 m toabout 2.5 m between adjacent orifices. Critical flow orifices 515 may befurther configured as described herein. Inner conduit 513 may be sealedat the bottom. Oxidizing fluid 517 may be provided into opening 514through critical flow orifices 515 of inner conduit 513.

Critical flow orifices 515 may be designed such that substantially thesame flow rate of oxidizing fluid 517 may be provided through eachcritical flow orifice. Critical flow orifices 515 may also providesubstantially uniform flow of oxidizing fluid 517 along a length ofconduit 512. Such flow may provide substantially uniform heating offormation 516 along the length of conduit 512.

Packing material 542 may enclose conduit 512 in overburden 540 of theformation. Packing material 542 may substantially inhibit flow of fluidsfrom opening 514 to surface 550. Packing material 542 may include anymaterial configurable to inhibit flow of fluids to surface 550 such ascement, sand, and/or gravel. Typically a conduit or an opening in thepacking remains to provide a path for oxidation products to reach thesurface.

Oxidation products 519 typically enter conduit 512 from opening 514.Oxidation products 519 may include carbon dioxide, oxides of nitrogen,oxides of sulfur, carbon monoxide, and/or other products resulting froma reaction of oxygen with hydrocarbons and/or carbon. Oxidation products519 may be removed through conduit 512 to surface 550. Oxidation product519 may flow along a face of reaction zone 524 in opening 514 untilproximate an upper end of opening 514 where oxidation product 519 mayflow into conduit 512. Oxidation products 519 may also be removedthrough one or more conduits disposed in opening 514 and/or in formation516. For example, oxidation products 519 may be removed through a secondconduit disposed in opening 514. Removing oxidation products 519 througha conduit may substantially inhibit oxidation products 519 from flowingto a production well disposed in formation 516. Critical flow orifices515 may also be configured to substantially inhibit oxidation products519 from entering inner conduit 513.

A flow rate of oxidation product 519 may be balanced with a flow rate ofoxidizing fluid 517 such that a substantially constant pressure ismaintained within opening 514. For a 100 m length of heated section, aflow rate of oxidizing fluid may be between about 0.5 standard cubicmeters per minute to about 5 standard cubic meters per minute, or about1.0 standard cubic meters per minute to about 4.0 standard cubic metersper minute, or, for example, about 1.7 standard cubic meters per minute.A flow rate of oxidizing fluid into the formation may be incrementallyincreased during use to accommodate expansion of the reaction zone. Apressure in the opening may be, for example, about 8 bar absolute.Oxidizing fluid 517 may oxidize at least a portion of the hydrocarbonsin heated portion 518 of hydrocarbon containing formation 516 atreaction zone 524. Heated portion 518 may have been initially heated toa temperature sufficient to support oxidation by an electric heater, asshown in FIG. 14, or by any other suitable system or method describedherein. In some embodiments, an electric heater may be placed inside orstrapped to the outside of conduit 513.

In certain embodiments it is beneficial to control the pressure withinthe opening 514 such that oxidation product and/or oxidation fluids areinhibited from flowing into the pyrolysis zone of the formation. In someinstances pressure within opening 514 will be balanced with pressurewithin the formation to do so.

Although the heat from the oxidation is transferred to the formation,oxidation product 519 (and excess oxidation fluid such as air) may besubstantially inhibited from flowing through the formation and/or to aproduction well within formation 516. Instead oxidation product 519 (andexcess oxidation fluid) is removed (e.g., through a conduit such asconduit 512) as is described herein. In this manner, heat is transferredto the formation from the oxidation but exposure of the pyrolysis zonewith oxidation product 519 and/or oxidation fluid may be substantiallyinhibited and/or prevented.

In certain embodiments, some pyrolysis product near the reaction zone524 may also be oxidized in reaction zone 524 in addition to the carbon.Oxidation of the pyrolysis product in reaction zone 524 may provideadditional heating of formation 516. When such oxidation of pyrolysisproduct occurs, it is desirable that oxidation product from suchoxidation be removed (e.g., through a conduit such as conduit 512) nearthe reaction zone as is described herein, thereby inhibitingcontamination of other pyrolysis product in the formation with oxidationproduct.

Conduit 512 may be configured to remove oxidation product 519 fromopening 514 in formation 516. As such, oxidizing fluid 517 in innerconduit 513 may be heated by heat exchange in overburden section 540from oxidation product 519 in conduit 512. Oxidation product 519 may becooled by transferring heat to oxidizing fluid 517. In this manner,oxidation of hydrocarbons within formation 516 may be more thermallyefficient.

Oxidizing fluid 517 may transport through reaction zone 524, or heatsource zone, by gas phase diffusion and/or convection. Diffusion ofoxidizing fluid 517 through reaction zone 524 may be more efficient atthe relatively high temperatures of oxidation. Diffusion of oxidizingfluid 517 may inhibit development of localized overheating and fingeringin the formation. Diffusion of oxidizing fluid 517 through formation 516is generally a mass transfer process. In the absence of an externalforce, a rate of diffusion for oxidizing fluid 517 may depend uponconcentration, pressure, and/or temperature of oxidizing fluid 517within formation 516. The rate of diffusion may also depend upon thediffusion coefficient of oxidizing fluid 517 through formation 516. Thediffusion coefficient may be determined by measurement or calculationbased on the kinetic theory of gases. In general, random motion ofoxidizing fluid 517 may transfer oxidizing fluid 517 through formation516 from a region of high concentration to a region of lowconcentration.

With time, reaction zone 524 may slowly extend radially to greaterdiameters from go opening 514 as hydrocarbons are oxidized. Reactionzone 524 may, in many embodiments, maintain a relatively constant width.For example, reaction zone 524 may extend radially at a rate of lessthan about 0.91 m per year for a hydrocarbon containing formation. Forexample, for a coal formation, reaction zone 524 may extend radially ata rate between about 0.5 m per year to about 1 m per year. For an oilshale formation, reaction zone 524 may extend radially about 2 m in thefirst year and at a lower rate in subsequent years due to an increase involume of reaction zone 524 as reaction zone 524 extends radially. Sucha lower rate may be about 1 m per year to about 1.5 m per year. Reactionzone 524 may extend at slower rates for hydrocarbon rich formations(e.g., coal) and at faster rates for formations with more inorganicmaterial in it (e.g., oil shale) since more hydrocarbons per volume areavailable for combustion in the hydrocarbon rich formations.

A flow rate of oxidizing fluid 517 into opening 514 may be increased asa diameter of reaction zone 524 increases to maintain the rate ofoxidation per unit volume at a substantially steady state. Thus, atemperature within reaction zone 524 may be maintained substantiallyconstant in some embodiments. The temperature within reaction zone 524may be between about 650° C. to about 900° C. or, for example, about760° C. The temperature may be maintained below a temperature thatresults in production of oxides of nitrogen (NO_(x)).

The temperature within reaction zone 524 may vary depending on, forexample, a desired heating rate of selected section 526. The temperaturewithin reaction zone 524 may be increased or decreased by increasing ordecreasing, respectively, a flow fate of oxidizing fluid 517 intoopening 514. A temperature of conduit 512, inner conduit 513, and/or anymetallurgical materials within opening 514 typically will not exceed amaximum operating temperature of the material. Maintaining thetemperature below the maximum operating temperature of a material mayinhibit excessive deformation and/or corrosion of the material.

An increase in the diameter of reaction zone 524 may allow forrelatively rapid heating of the hydrocarbon containing formation 516. Asthe diameter of reaction zone 524 increases, an amount of heat generatedper time in reaction zone 524 may also increase. Increasing an amount ofheat generated per time in the reaction zone will in many instancesincrease heating rate of the formation 516 over a period of time, evenwithout increasing the temperature in the reaction zone or thetemperature at conduit 513. Thus, increased heating may be achieved overtime without installing additional heat sources, and without increasingtemperatures adjacent to wellbores. In some embodiments the heatingrates may be increased while allowing the temperatures to decrease(allowing temperatures to decrease may often lengthen the life of theequipment used).

By utilizing the carbon in the formation as a fuel, the naturaldistributed combustor may save significantly on energy costs. Thus, aneconomical process may be provided for heating formations that mayotherwise be economically unsuitable for heating by other methods. Also,fewer heaters may be placed over an extended area of formation 516. Thismay provide for a reduced equipment cost associated with heating theformation 516.

The heat generated at reaction zone 524 may transfer by thermalconduction to selected section 526 of formation 516. In addition,generated heat may transfer from a reaction zone to the selected sectionto a lesser extent by convection heat transfer. Selected section 526,sometimes referred to herein as the “pyrolysis zone,” may besubstantially adjacent to reaction zone 524. Since oxidation product(and excess oxidation fluid such as air) is typically removed from thereaction zone, the pyrolysis zone can receive heat from the reactionzone without being exposed to oxidation product, or oxidants, that arein the reaction zone. Oxidation product and/or oxidation fluids maycause the formation of undesirable formation products if they arepresent in the pyrolysis zone. For example, in certain embodiments it isdesirable to conduct pyrolysis in a reducing environment. Thus, it isoften useful to allow heat to transfer from the reaction zone to thepyrolysis zone while inhibiting or preventing oxidation product and/oroxidation fluid from reaching the pyrolysis zone.

Pyrolysis of hydrocarbons, or other heat-controlled processes, may takeplace in heated selected section 526. Selected section 526 may be at atemperature between about 270° C. to about 400° C. for pyrolysis. Thetemperature of selected section 526 may be increased by heat transferfrom reaction zone 524. A rate of temperature increase may be selectedas in any of the embodiments described herein. A temperature information 516, selected section 526, and/or reaction zone 524 may becontrolled such that production of oxides of nitrogen may besubstantially inhibited. Oxides of nitrogen are often produced attemperatures above about 1200° C.

A temperature within opening 514 may be monitored with a thermocoupledisposed in opening 514. Alternatively, a thermocouple may be disposedon conduit 512 and/or disposed on a face of reaction zone 524, and atemperature may be monitored accordingly. The temperature in theformation may be monitored by the thermocouple, and power input oroxidant introduced into the formation may be controlled based upon themonitored temperature such that the monitored temperature is maintainedwithin a selected range. The selected range may vary, depending on, forexample, a desired heating rate of formation 516. In an embodiment,monitored temperature is maintained within a selected range byincreasing or decreasing a flow rate of oxidizing fluid 517. Forexample, if a temperature within opening 514 falls below a selectedrange of temperatures, the flow rate of oxidizing fluid 517 is increasedto increase the combustion and thereby increase the temperature withinopening 514.

In certain embodiments one or more natural distributed combustors may beplaced along strike and/or horizontally. Doing so tends to reducepressure differentials along the heated length of the well. The absenceof pressure differentials may make controlling the temperature generatedalong a length of the heater more uniform and easier to control.

In some embodiments, a presence of air or oxygen (O₂) in oxidationproduct 519 may be monitored. Alternatively, an amount of nitrogen,carbon monoxide, carbon dioxide, oxides of nitrogen, oxides of sulfur,etc. may be monitored in oxidation product 519. Monitoring thecomposition and/or quantity of oxidation product 519 may be useful forheat balances. for process diagnostics, process control, etc.

FIG. 11 illustrates an embodiment of a section of overburden with anatural distributed combustor as described in FIG. 10. Overburden casing541 may be disposed in overburden 540 of formation 516. Overburdencasing 541 may be substantially surrounded by materials (e.g., aninsulating material such as cement) that may substantially inhibitheating of overburden 540. Overburden casing 541 may be made of a metalmaterial such as, but not limited to, carbon steel, or 304 stainlesssteel.

Overburden casing may be placed in reinforcing material 544 inoverburden 540. Reinforcing material 544 may be, for example, cement,sand, concrete, etc. Packing material 542 may be disposed betweenoverburden casing 541 and opening 514 in the formation. Packing material542 may be any substantially non-porous material (e.g., cement,concrete, grout, etc.). Packing material 542 may inhibit flow of fluidoutside of conduit 512 and between opening 514 and surface 550. Innerconduit 513 may provide a fluid into opening 514 in formation 516.Conduit 512 may remove a combustion product (or excess oxidation fluid)from opening 514 in formation 516. Diameter of conduit 512 may bedetermined by an amount of the combustion product produced by oxidationin the natural distributed combustor. For example, a larger diameter maybe required for a greater amount of exhaust product produced by thenatural distributed combustor heater.

In an alternative embodiment, at least a portion of the formation may beheated to a temperature such that at least a portion of the hydrocarboncontaining formation may be converted to coke and/or char. Coke and/orchar may be formed at temperatures above about 400° C. and at a highheating rate (e.g., above about 10° C./day). In the presence of anoxidizing fluid, the coke or char will oxidize. Heat may be generatedfrom the oxidation of coke or char as in any of the embodimentsdescribed herein.

FIG. 12 illustrates an embodiment of a natural distributed combustorheater. Insulated conductor 562 may be coupled to conduit 532 and placedin opening 514 in formation 516. Insulated conductor 562 may be disposedinternal to conduit 532 (thereby allowing retrieval of the insulatedconductor 562), or, alternately, coupled to an external surface ofconduit 532. Such insulating material may include, for example,minerals, ceramics, etc. Conduit 532 may have critical flow orifices 515disposed along its length within opening 514. Critical flow orifices 515may be configured as described herein. Electrical current may be appliedto insulated conductor 562 to generate radiant heat in opening 514.Conduit 532 may be configured to serve as a return for current.Insulated conductor 562 may be configured to heat portion 518 of theformation to a temperature sufficient to support oxidation ofhydrocarbons. Portion 518, reaction zone 524, and selected section 526may have characteristics as described herein. Such a temperature mayinclude temperatures as described herein.

Oxidizing fluid source 508 may provide oxidizing fluid into conduit 532.Oxidizing fluid may be provided into opening 514 through critical floworifices 515 in conduit 532. Oxidizing fluid may oxidize at least aportion of the hydrocarbon containing formation in reaction zone 524.Reaction zone 524 may have characteristics as described herein. Heatgenerated at reaction zone 524 may transfer heat to selected section526, for example, by convection, radiation, and/or conduction. Oxidationproduct may be removed through a separate conduit placed in opening 514or through an opening 543 in overburden casing 541. The separate conduitmay be configured as described herein. Packing material 542 andreinforcing material 544 may be configured as described herein.

FIG. 13 illustrates an embodiment of a natural distributed combustorheater with an added fuel conduit. Fuel conduit 536 may be disposed intoopening 514. It may be disposed substantially adjacent to conduit 533 incertain embodiments. Fuel conduit 536 may have critical flow orifices535 along its length within opening 514. Conduit 533 may have criticalflow orifices 515 along its length within opening 514. Critical floworifices 515 may be configured as described herein. Critical floworifices 535 and critical flow orifices 515 may be placed on fuelconduit 536 and conduit 533, respectively, such that a fuel fluidprovided through fuel conduit 536 and an oxidizing fluid providedthrough conduit 533 may not substantially heat fuel conduit 536 and/orconduit 533 upon reaction. For example, the fuel fluid and the oxidizingfluid may react upon contact with each other, thereby producing heatfrom the reaction. The heat from this reaction may heat fuel conduit 536and/or conduit 533 to a temperature sufficient to substantially beginmelting metallurgical materials in fuel conduit 536 and/or conduit 533if the reaction takes place proximate to fuel conduit 536 and/or conduit533. Therefore, a design for disposing critical flow orifices 535 onfuel conduit 536 and critical flow orifices 515 on conduit 533 may beprovided such that the fuel fluid and the oxidizing fluid may notsubstantially react proximate to the conduits. For example, conduits 536and 533 may be spatially coupled together such that orifices that spiralaround the conduits are oriented in opposite directions.

Reaction of the fuel fluid and the oxidizing fluid may produce heat. Thefuel fluid may be, for example, natural gas, ethane, hydrogen orsynthesis gas that is generated in the in situ process in another partof the formation. The produced heat may be configured to heat portion518 to a temperature sufficient to support oxidation of hydrocarbons.Upon heating of portion 518 to a temperature sufficient to supportoxidation, a flow of fuel fluid into opening 514 may be turned down ormay be turned off. Alternatively, the supply of fuel may be continuedthroughout the heating of the formation, thereby utilizing the storedheat in the carbon to maintain the temperature in opening 514 above theautoignition temperature of the fuel.

The oxidizing fluid may oxidize at least a portion of the hydrocarbonsat reaction zone 524. Generated heat will transfer heat to selectedsection 526, for example, by radiation, convection, and/or conduction.An oxidation product may be removed through a separate conduit placed inopening 514 or through an opening 543 in overburden casing 541.

FIG. 14 illustrates an embodiment of a system configured to heat ahydrocarbon containing formation. Electric heater 510 may be disposedwithin opening 514 in hydrocarbon containing formation 516. Opening 514may be formed through overburden 540 into formation 516. Opening 514 maybe at least about 5 cm in diameter. Opening 514 may, as an example, havea diameter of about 13 cm. Electric heater 510 may heat at least portion518 of hydrocarbon containing formation 516 to a temperature sufficientto support oxidation (e.g., about 260° C.). Portion 518 may have a widthof about 1 m. An oxidizing fluid (e.g., liquid or gas) may be providedinto the opening through conduit 512 or any other appropriate fluidtransfer mechanism. Conduit 512 may have critical flow orifices 515disposed along a length of the conduit. Critical flow orifices 515 maybe configured as described herein.

For example, conduit 512 may be a pipe or tube configured to provide theoxidizing fluid into opening 514 from oxidizing fluid source 508. Forexample, conduit 512 may be a stainless steel tube. The oxidizing fluidmay include air or any other oxygen containing fluid (e.g., hydrogenperoxide, oxides of nitrogen, ozone). Mixtures of oxidizing fluids maybe used. An oxidizing fluid mixture may include, for example, a fluidincluding fifty percent oxygen and fifty percent nitrogen. The oxidizingfluid may also, in some embodiments, include compounds that releaseoxygen when heated such as hydrogen peroxide. The oxidizing fluid mayoxidize at least a portion of the hydrocarbons in the formation.

In some embodiments, a heat exchanger disposed external to the formationmay be configured to heat the oxidizing fluid. The heated oxidizingfluid may be provided into the opening from (directly or indirectly) theheat exchanger. For example, the heated oxidizing fluid may be providedfrom the heat exchanger into the opening through a conduit disposed inthe opening and coupled to the heat exchanger. In some embodiments theconduit may be a stainless steel tube. The heated oxidizing fluid may beconfigured to heat, or at least contribute to the heating of, at least aportion of the formation to a temperature sufficient to supportoxidation of hydrocarbons. After the heated portion reaches such atemperature, heating of the oxidizing fluid in the heat exchanger may bereduced or may be turned off.

FIG. 15 illustrates another embodiment of a system configured to heat ahydrocarbon containing formation. Heat exchanger 520 may be disposedexternal to opening 514 in hydrocarbon containing formation 516. Opening514 may be formed through overburden 540 into formation 516. Heatexchanger 520 may provide heat from another surface process, or it mayinclude a heater (e.g., an electric or combustion heater). Oxidizingfluid source 508 may provide an oxidizing fluid to heat exchanger 520.Heat exchanger 520 may heat an oxidizing fluid (e.g., above 200° C. or atemperature sufficient to support oxidation of hydrocarbons). The heatedoxidizing fluid may be provided into opening 514 through conduit 521.Conduit 521 may have critical flow orifices 515 disposed along a lengthof the conduit. Critical flow orifices 515 may be configured asdescribed herein. The heated oxidizing fluid may heat, or at leastcontribute to the heating of, at least portion 518 of the formation to atemperature sufficient to support oxidation of hydrocarbons. Theoxidizing fluid may oxidize at least a portion of the hydrocarbons inthe formation.

In another embodiment, a fuel fluid may be oxidized in a heater locatedexternal to a hydrocarbon containing formation. The fuel fluid may beoxidized with an oxidizing fluid in the heater. As an example, theheater may be a flame-ignited heater. A fuel fluid may include any fluidconfigured to react with oxygen. Fuel fluids may be, but are not limitedto, methane, ethane, propane, other hydrocarbons, hydrogen, synthesisgas, or combinations thereof. The oxidized fuel fluid may be providedinto the opening from the heater through a conduit and oxidationproducts and unreacted fuel may return to the surface through anotherconduit in the overburden. The conduits may be coupled within theoverburden. In some embodiments, the conduits may be concentricallyplaced. The oxidized fuel fluid may be configured to heat, or at leastcontribute to the heating of, at least a portion of the formation to atemperature sufficient to support oxidation of hydrocarbons. Uponreaching such a temperature, the oxidized fuel fluid may be replacedwith an oxidizing fluid. The oxidizing fluid may oxidize at least aportion of the hydrocarbons at a reaction zone within the formation.

An electric heater may be configured to heat a portion of thehydrocarbon containing formation to a temperature sufficient to supportoxidation of hydrocarbons. The portion may be proximate to orsubstantially adjacent to the opening in the formation. The portion mayalso radially extend a width of less than approximately 1 m from theopening. A width of the portion may vary, however, depending on, forexample, a power supplied to the heater. An oxidizing fluid may beprovided to the opening for oxidation of hydrocarbons. Oxidation of thehydrocarbons may be configured to heat the hydrocarbon containingformation in a process of natural distributed combustion. Electricalcurrent applied to the electric heater may subsequently be reduced ormay be turned off. Thus, natural distributed combustion may beconfigured, in conjunction with an electric heater, to provide a reducedinput energy cost method to heat the hydrocarbon containing formationcompared to using an electric heater.

An insulated conductor heater may be a heater element of a heat source.In an embodiment of an insulated conductor heater, the insulatedconductor heater is a mineral insulated cable or rod. An insulatedconductor heater may be placed in an opening in a hydrocarbon containingformation. The insulated conductor heater may be placed in an uncasedopening in the hydrocarbon containing formation. Placing the heater inan uncased opening in the hydrocarbon containing formation may allowheat transfer from the heater to the formation by radiation, as well as,conduction. In addition, using an uncased opening may also allowretrieval of the heater from the well, if necessary, and may eliminatethe cost of the casing. Alternately, the insulated conductor heater maybe placed within a casing in the formation; may be cemented within theformation; or may be packed in an opening with sand, gravel, or otherfill material. The insulated conductor heater may be supported on asupport member positioned within the opening. The support member may bea cable, rod, or a conduit (e.g., a pipe). The support member may bemade of a metal, ceramic, inorganic material, or combinations thereof.Portions of a support member may be exposed to formation fluids and heatduring use, so the support member may be chemically resistant andthermally resistant.

Ties, spot welds and/or other types of connectors may be used to couplethe insulated conductor heater to the support member at variouslocations along a length of the insulated conductor heater. The supportmember may be attached to a wellhead at an upper surface of theformation. In an alternate embodiment of an insulated conductor heater,the insulated conductor heater is designed to have sufficient structuralstrength so that a support member is not needed. The insulated conductorheater will in many instances have some flexibility to inhibit thermalexpansion damage when heated or cooled.

In certain embodiments, insulated conductor heaters may be placed inwellbores without support members and/or centralizers. This can beaccomplished for heaters if the insulated conductor has a suitablecombination of temperature and corrosion resistance, creep strength,length, thickness (diameter) and metallurgy that will inhibit failure ofthe insulated conductor during use. In an embodiment, insulatedconductors that are heated to a working temperature of about 700° C. areless than about 150 meters in length, are made of 310 stainless steel,and may be used without support members.

FIG. 16 depicts a perspective view of an end portion of an embodiment ofan insulated conductor heater 562. An insulated conductor heater mayhave any desired cross sectional shape, such as, but not limited toround (as shown in FIG. 16), triangular, ellipsoidal, rectangular,hexagonal or irregular shape. An insulated conductor heater may includeconductor 575, electrical insulation 576 and sheath 577. The conductor575 may resistively heat when an electrical current passes through theconductor. An alternating or direct current may be used to heat theconductor 575. In an embodiment, a 60 cycle AC current may be used.

In some embodiments, the electrical insulation 576 may inhibit currentleakage and may inhibit arcing to the sheath 577. The electricalinsulation 576 may also thermally conduct heat generated in theconductor 575 to the sheath 577. The sheath 577 may radiate or conductheat to the formation. An insulated conductor heater 562 may be 1000 mor more in length. In an embodiment of an insulated conductor heater,the insulated conductor heater 562 may have a length from about 15 m toabout 950 m. Longer or shorter insulated conductors may also be used tomeet specific application needs. In embodiments of insulated conductorheaters, purchased insulated conductor heaters have lengths of about 100m to 500 m (e.g., 230 m). In certain embodiments, dimensions of sheathsand/or conductors of an insulated conductor may be formed so that theinsulated conductors have enough strength to be self supporting even atupper working temperatures. Such insulated cables may be suspended fromwellheads or supports positioned near an interface between an overburdenand a hydrocarbon containing formation without the need for supportmembers extending into the hydrocarbon formation along with theinsulated conductors.

In an embodiment, a higher frequency current may be used to takeadvantage of the skin effect in certain metals. In some embodiments, a60 cycle AC current may be used in combination with conductors made ofmetals that exhibit pronounced skin effects. For example, ferromagneticmetals like iron alloys and nickel may exhibit a skin effect. The skineffect confines the current to a region close to the outer surface ofthe conductor, thereby effectively increasing the resistance of theconductor. A higher resistance may be desired to decrease the operatingcurrent, minimize ohmic losses in surface cables, and also minimize thecost of surface facilities.

As illustrated in FIG. 17, an insulated conductor heater 562 will inmany instances be designed to operate at a power level of up to about1650 watts/meter. The insulated conductor heater 562 may typicallyoperate at a power level between about 500 watts/meter and about 1150watts/meter when heating a formation. The insulated conductor heater 562may be designed so that a maximum voltage level at a typical operatingtemperature does not cause substantial thermal and/or electricalbreakdown of electrical insulation 576. The insulated conductor heater562 may be designed so that the sheath 577 does not exceed a temperaturethat will result in a significant reduction in corrosion resistanceproperties of the sheath material.

In an embodiment of an insulated conductor heater 562, the conductor 575may be designed to reach temperatures within a range between about 650°C. to about 870° C., and the sheath 577 may be designed to reachtemperatures within a range between about 535° C. to about 760° C.Insulated conductors having other operating ranges may be formed to meetspecific operational requirements. In an embodiment of an insulatedconductor heater 562, the conductor 575 is designed to operate at about760° C., the sheath 577 is designed to operate at about 650° C., and theinsulated conductor heater is designed to dissipate about 820watts/meter.

An insulated conductor heater 562 may have one or more conductors 575.For example, a single insulated conductor heater may have threeconductors within electrical insulation that are surrounded by a sheath.FIG. 16 depicts an insulated conductor heater 562 having a singleconductor 575. The conductor may be made of metal. The material used toform a conductor may be, but is not limited to, nichrome, nickel, and anumber of alloys made from copper and nickel in increasing nickelconcentrations from pure copper to Alloy 30, Alloy 60, Alloy 180 andMonel. Alloys of copper and nickel may advantageously have betterelectrical resistance properties than substantially pure nickel orcopper.

In an embodiment, the conductor may be chosen to have a diameter and aresistivity at operating temperatures such that its resistance, asderived from Ohm's law, makes it electrically and structurally stablefor the chosen power dissipation per meter, the length of the heater,and/or the maximum voltage allowed to pass through the conductor. In analternate embodiment, the conductor may be designed, using Maxwell'sequations, to make use of skin effect heating in and/or on theconductor.

The conductor may be made of different material along a length of theinsulated conductor heater. For example, a first section of theconductor may be made of a material that has a significantly lowerresistance than a second section of the conductor. The first section maybe placed adjacent to a formation layer that does not need to be heatedto as high a temperature as a second formation layer that is adjacent tothe second section. The resistivity of various sections of conductor maybe adjusted by having a variable diameter and/or by having conductorsections made of different materials.

A diameter of a conductor 575 may typically be between about 1.3 mm toabout 10.2 mm. Smaller or larger diameters may also be used to haveconductors with desired resistivity characteristics. In an embodiment ofan insulated conductor heater, the conductor is made of Alloy 60 thathas a diameter of about 5.8 mm.

As illustrated in FIG. 16, an electrical insulator 576 of an insulatedconductor heater 562 may be made of a variety of materials. Pressure maybe used to place electrical insulator powder between a conductor 575 anda sheath 577. Low flow characteristics and other properties of thepowder and/or the sheaths and conductors may inhibit the powder fromflowing out of the sheaths. Commonly used powders may include, but arenot limited to, MgO, Al₂O₃, Zirconia, BeO, different chemical variationsof Spinels, and combinations thereof. MgO may provide good thermalconductivity and electrical insulation properties. The desiredelectrical insulation properties include low leakage current and highdielectric strength. A low leakage current decreases the possibility ofthermal breakdown and the high dielectric strength decreases thepossibility of arcing across the insulator. Thermal breakdown can occurif the leakage current causes a progressive rise in the temperature ofthe insulator leading also to arcing across the insulator. An amount ofimpurities 578 in the electrical insulator powder may be tailored toprovide required dielectric strength and a low level of leakage current.The impurities 578 added may be, but are not limited to, CaO, Fe₂O₃,Al₂O₃, and other metal oxides. Low porosity of the electrical insulationtends to reduce leakage current and increase dielectric strength. Lowporosity may be achieved by increased packing of the MgO powder duringfabrication or by filling of the pore space in the MgO powder with othergranular materials, for example, Al₂O₃.

The impurities 578 added to the electrical insulator powder may haveparticle sizes that are smaller than the particle sizes of the powderedelectrical insulator. The small particles may occupy pore space betweenthe larger particles of the electrical insulator so that the porosity ofthe electrical insulator is reduced. Examples of powdered electricalinsulators that may be used to form electrical insulation 576 are “H”mix manufactured by Idaho Laboratories Corporation (Idaho Falls, Id.),or Standard MgO used by Pyrotenax Cable Company (Trenton, Ontario) forhigh temperature applications. In addition, other powdered electricalinsulators may be used.

A sheath 577 of an insulated conductor heater 562 may be an outermetallic layer. The sheath 577 may be in contact with hot formationfluids. The sheath 577 may need to be made of a material having a highresistance to corrosion at elevated temperatures. Alloys that may beused in a desired operating temperature range of the sheath include, butare not limited to, 304 stainless steel, 310 stainless steel, Incoloy800, and Inconel 600. The thickness of the sheath has to be sufficientto last for three to ten years in a hot and corrosive environment. Athickness of the sheath may generally vary between about 1 mm and about2.5 mm. For example, a 1.3 mm thick 310 stainless steel outer layerprovides a sheath 577 that is able to provide good chemical resistanceto sulfidation corrosion in a heated zone of a formation for a period ofover 3 years. Larger or smaller sheath thicknesses may be used to meetspecific application requirements.

An insulated conductor heater may be tested after fabrication. Theinsulated conductor heater may be required to withstand 2-3 times anoperating voltage at a selected operating temperature. Also, selectedsamples of produced insulated conductor heaters may be required towithstand 1000 VAC at 760° C. for one month.

As illustrated in FIG. 17a, a short flexible transition conductor 571may be connected to a lead-in conductor 572 using a connection 569 madeduring heater installation in the field. The transition conductor 571may, for example, be a flexible, low resistivity, stranded copper cablethat is surrounded by rubber or polymer insulation. A transitionconductor 571 may typically be between about 1.5 m and about 3 m,although longer or shorter transition conductors may be used toaccommodate particular needs. Temperature resistant cable may be used astransition conductor 571. The transition conductor 571 may also beconnected to a short length of an insulated conductor heater that isless resistive than a primary heating section of the insulated conductorheater. The less resistive portion of the insulated conductor heater maybe referred to as a “cold pin” 568.

A cold pin 568 may be designed to dissipate about one tenth to about onefifth of the power per unit length as is dissipated in a unit length ofthe primary heating section. Cold pins may typically be between about1.5 m to about 15 m, although shorter or longer lengths may be used toaccommodate specific application needs. In an embodiment, the conductorof a cold pin section is copper with a diameter of about 6.9 mm and alength of 9.1 m. The electrical insulation is the same type ofinsulation used in the primary heating section. A sheath of the cold pinmay be made of Inconel 600. Chloride corrosion cracking in the cold pinregion may occur, so a chloride corrosion resistant metal such asInconel 600 may be used as the sheath.

As illustrated in FIG. 17a, a small, epoxy filled canister 573 may beused to create a connection between a transition conductor 571 and acold pin 568. Cold pins 568 may be connected to the primary heatingsections of insulated conductor 562 heaters by “splices” 567. The lengthof the cold pin 568 may be sufficient to significantly reduce atemperature of the insulated conductor heater 562. The heater section ofthe insulated conductor heater 562 may operate from about 530° C. toabout 760° C., the splice 567 may be at a temperature from about 260° C.to about 370° C., and the temperature at the lead-in cable connection tothe cold pin may be from about 40° C. to about 90° C. In addition to acold pin at a top end of the insulated conductor heater, a cold pin mayalso be placed at a bottom end of the insulated conductor heater. Thecold pin at the bottom end may in many instances make a bottomtermination easier to manufacture.

Splice material may have to withstand a temperature equal to half of atarget zone operating temperature. Density of electrical insulation inthe splice should in many instances be high enough to withstand therequired temperature and the operating voltage.

A splice 567 may be required to withstand 1000 VAC at 480° C. Splicematerial may be high temperature splices made by Idaho LaboratoriesCorporation or by Pyrotenax Cable Company. A splice may be an internaltype of splice or an external splice. An internal splice is typicallymade without welds on the sheath of the insulated conductor heater. Thelack of weld on the sheath may avoid potential weak spots (mechanicaland/or electrical) on the insulated cable heater. An external splice isa weld made to couple sheaths of two insulated conductor heaterstogether. An external splice may need to be leak tested prior toinsertion of the insulated cable heater into a formation. Laser welds ororbital TIG (tungsten inert gas) welds may be used to form externalsplices. An additional strain relief assembly may be placed around anexternal splice to improve the splice's resistance to bending and toprotect the external splice against partial or total parting.

An insulated conductor assembly may include heating sections, cold pins,splices, and termination canisters and flexible transition conductors.The insulated conductor assembly may need to be examined andelectrically tested before installation of the assembly into an opening,in a formation. The assembly may need to be examined for competent weldsand to make sure that there are no holes in the sheath anywhere alongthe whole heater (including, the heated section, the cold-pins, thesplices and the termination cans). Periodic X-ray spot checking of thecommercial product may need to be made. The whole cable may be immersedin water prior to electrical testing. Electrical testing of the assemblymay need to show more than 2000 megaohms at 500 VAC at room temperatureafter water immersion. In addition, the assembly may need to beconnected to 1000 VAC and show less than about 10 microamps per meter ofresistive leakage current at room temperature. Also, a check on leakagecurrent at about 760° C. may need to show less than about 0.4 milliampsper meter.

There are a number of companies that manufacture insulated conductorheaters. Such manufacturers include, but are not limited to, MI CableTechnologies (Calgary, Alberta), Pyrotenax Cable Company (Trenton,Ontario), Idaho Laboratories Corporation (Idaho Falls, Id.), and Watlow(St. Louis, Mo.). As an example, an insulated conductor heater may beordered from Idaho Laboratories as cable model 355-A90-310-“H”30′/750′/30′ with Inconel 600 sheath for the cold-pins, three phase Yconfiguration and bottom jointed conductors. The required specificationfor the heater should also include 1000 VAC, 1400° F. quality cable inaddition to the preferred mode specifications described above. Thedesignator 355 specifies the cable OD(0.355″), A90 specifies theconductor material, 310 specifies the heated zone sheath alloy (SS 310),“H” specifies the MgO mix, 30′/750′/30′ specifies about a 230 m heatedzone with cold-pins top and bottom having about 9 m lengths. A similarpart number with the same specification using high temperature Standardpurity MgO cable may be ordered from Pyrotenax Cable Company.

One or more insulated conductor heaters may be placed within an openingin a formation to form a heat source or heat sources. Electrical currentmay be passed through each insulated conductor heater in the opening toheat the formation. Alternately, electrical current may be passedthrough selected insulated conductor heaters in an opening. The unusedconductors may be backup heaters. Insulated conductor heaters may beelectrically coupled to a power source in any convenient manner. Eachend of an insulated conductor heater may be coupled to lead-in cablesthat pass through a wellhead. Such a configuration typically has a 180°bend (a “hairpin” bend) or turn located near a bottom of the heatsource. An insulated conductor heater that includes a 180° bend or turnmay not require a bottom termination, but the 180° bend or turn may bean electrical and/or structural weakness in the heater. Insulatedconductor heaters may be electrically coupled together in series, inparallel, or in series and parallel combinations. In some embodiments ofheat sources, electrical current may pass into the conductor of aninsulated conductor heater and may returned through the sheath of theinsulated conductor heater by connecting the conductor 575 to the sheath577 at the bottom of the heat source.

In an embodiment of a heat source depicted in FIG. 17, three insulatedconductor heaters 562 are electrically coupled in a 3-phase Yconfiguration to a power supply. The power supply may provide a 60 cycleAC current to the electrical conductors. No bottom connection may berequired for the insulated conductor heaters. Alternately, all threeconductors of the three phase circuit may be connected together near thebottom of a heat source opening. The connection may be made directly atends of heating sections of the insulated conductor heaters or at endsof cold pins coupled to the heating sections at the bottom of theinsulated conductor heaters. The bottom connections may be made withinsulator filled and sealed canisters or with epoxy filled canisters.The insulator may be the same composition as the insulator used as theelectrical insulation.

The three insulated conductor heaters depicted in FIG. 17 may be coupledto support member 564 using centralizers 566. Alternatively, the threeinsulated conductor heaters may be strapped directly to the support tubeusing metal straps. Centralizers 566 may be configured to maintain alocation of insulated conductor heaters 562 on support member 564.Centralizers 566 may be made of, for example, metal, ceramic or acombination thereof. The metal may be stainless steel or any other typeof metal able to withstand a corrosive and hot environment. In someembodiments, centralizers 566 may be simple bowed metal strips welded tothe support member at distances less than about 6 meters. A ceramic usedin centralizer 566 may be, but is not limited to, Al₂O₃, MgO or otherinsulator. Centralizers 566 may be configured to maintain a location ofinsulated conductor heaters 562 on support member 564 such that movementof insulated conductor heaters may be substantially inhibited atoperating temperatures of the insulated conductor heaters. Insulatedconductor heaters 562 may also be somewhat flexible to withstandexpansion of support member 564 during heating. Centralizers 566 mayalso be configured as described in any of the embodiments herein.

Support member 564, insulated conductor heater 562, and centralizers 566may be placed in opening 514 in hydrocarbon containing formation 516.Insulated conductor heaters 562 may be coupled to bottom conductorjunction 570 using cold pin transition conductor 568. Bottom conductorjunction 570 may electrically couple each insulated conductor heater 562to each other. Bottom conductor junction 570 may include materials thatare electrically conducting and do not melt at temperatures found inopening 514. Cold pin transition conductor 568 may be an insulatedconductor heater having lower electrical resistance than insulatedconductor heater 562. As illustrated in FIG. 17a, cold pin 568 may becoupled to transition conductor 571 and insulated conductor heater 562.Cold pin transition conductor 568 may provide a temperature transitionbetween transition conductor 571 and insulated conductor heater 562.

Lead-in conductor 572 may be coupled to wellhead 590 to provideelectrical power to insulated conductor heater 562. Wellhead 590 may beconfigured as shown in FIG. 18 and as described in any of theembodiments herein. Lead-in conductor 572 may be made of a relativelylow electrical resistance conductor such that relatively little orsubstantially no heat may be generated from electrical current passingthrough lead-in conductor 572. For example, the lead-in conductor mayinclude, but may not be limited to, a rubber insulated stranded copperwire, but the lead-in conductor may also be a mineral-insulatedconductor with a copper core. Lead-in conductor 572 may couple to awellhead 590 at surface 550 through a sealing flange located betweenoverburden 540 and surface 550. The sealing flange 590 c may beconfigured as shown in FIG. 18 and as described in any of theembodiments herein. The sealing flange may substantially inhibit fluidfrom escaping from opening 514 to surface 550.

Packing material 542 (see FIG. 17) may optionally be placed betweenoverburden casing 541 and opening 514. Overburden casing 541 may includeany materials configured to substantially contain cement 544. In anembodiment of a heater source, overburden casing is an 7.6 cm (3 inch)diameter carbon steel, schedule 40 pipe. Packing material 542 may beconfigured to inhibit fluid from flowing from opening 514 to surface550. Overburden casing 541 may be placed in cement 544 in overburden 540of formation 516. Cement 544 may include, for example, Class G or ClassH Portland cement mixed with silica flour for improved high temperatureperformance, slag or silica flour, and/or a mixture thereof (e.g., about1.58 grams per cubic centimeter slag/silica flour). In selected heatsource embodiments, cement 544 extends radially a width of from about 5cm to about 25 cm. In some embodiments cement 544 may extend radially awidth of about 10 cm to about 15 cm. In some other embodiments, cement544 may be designed to inhibit heat transfer from conductor 564 intoformation 540 within the overburden.

In certain embodiments one or more conduits may be provided to supplyadditional components (e.g., nitrogen, carbon dioxide, reducing agentssuch as gas containing hydrogen, etc.) to formation openings, to bleedoff fluids, and/or to control pressure. Formation pressures tend to behighest near heating sources and thus it is often beneficial to havepressure control equipment proximate the heating source. In someembodiments adding a reducing agent proximate the heating source assistsin providing a more favorable pyrolysis environment (e.g., a higherhydrogen partial pressure). Since permeability and porosity tend toincrease more quickly proximate the heating source, it is often optimalto add a reducing agent proximate the heating source so that thereducing agent can more easily move into the formation.

In FIG. 17, for example, conduit 5000 may be provided to add gas fromgas source 5003, through valve 5001, and into opening 514 (an opening5004 is provided in packing material 542 to allow gas to pass intoopening 514). Conduit 5000 and valve 5002 may also be used at differenttimes to bleed off pressure and/or control pressure proximate to opening514. In FIG. 19, for example, conduit 5010 may be provided to add gasfrom gas source 5013, through valve 5011, and into opening 514 (anopening is provided in cement 544 to allow gas to pass into opening514). Conduit 5010 and valve 5012 may also be used at different times tobleed off pressure and/or control pressure proximate to opening 514. Itis to be understood that any of the heating sources described herein mayalso be equipped with conduits to supply additional components, bleedoff fluids, and/or to control pressure.

Support member 564 and lead-in conductor 572 may be coupled to wellhead590 at surface 550 of formation 516. Surface conductor 545 may enclosecement 544 and may couple to wellhead 590. Embodiments of heater sourcesurface conductor 545 may have a diameter of about 10.16 cm to about30.48 cm or, for example, a diameter of about 22 cm. Embodiments ofsurface casings may extend to depths of approximately 3 m toapproximately 515 m into an opening in the formation. Alternatively, thesurface casing may extend to a depth of approximately 9 m into theopening. Electrical current may be supplied from a power source toinsulated conductor heater 562 to generate heat due to the electricalresistance of conductor 575 as illustrated in FIG. 16. As an example, avoltage of about 330 volts and a current of about 266 amps are suppliedto insulated conductors 562 to generate a heat of about 1150 watts/meterin insulated conductor heater 562. Heat generated from the threeinsulated conductor heaters 562 may transfer (e.g., by radiation) withinopening 514 to heat at least a portion of the formation 516.

An appropriate configuration of an insulated conductor heater may bedetermined by optimizing a material cost of the heater based on a lengthof heater, a power required per meter of conductor, and a desiredoperating voltage. In addition, an operating current and voltage may bechosen to optimize the cost of input electrical energy in conjunctionwith a material cost of the insulated conductor heaters. For example, asinput electrical energy increases, the cost of materials needed towithstand the higher voltage may also increase. The insulated conductorheaters may be configured to generate a radiant heat of approximately650 watts/meter of conductor to approximately 1650 watts/meter ofconductor. The insulated conductor heater may operate at a temperaturebetween approximately 530° C. and approximately 760° C. within aformation.

Heat generated by an insulated conductor heater may heat at least aportion of a hydrocarbon containing formation. In some embodiments heatmay be transferred to the formation substantially by radiation of thegenerated heat to the formation. Some heat may be transferred byconduction or convection of heat due to gases present in the opening.The opening may be an uncased opening. An uncased opening eliminatescost associated with thermally cementing the heater to the formation,costs associated with a casing, and/or costs of packing a heater withinan opening. In addition, the heat transfer by radiation is generallymore efficient than by conduction so the heaters will operate at lowertemperatures in an open wellbore. The conductive heat transfer may beenhanced by the addition of a gas in the opening at pressures up toabout 27 bar absolute. The gas may include, but may not be limited to,carbon dioxide and/or helium. Still another advantage is that theheating assembly will be free to undergo thermal expansion. Yet anotheradvantage is that the heaters may be replaceable.

The insulated conductor heater, as described in any of the embodimentsherein, may be installed in opening 514 by any method known in the art.In an embodiment, more than one spooling assembly may be used to installboth the electric heater and a support member simultaneously. U.S. Pat.No. 4,572,299 issued to Van Egmond et al., which is incorporated byreference as if fully set forth herein, describes spooling an electricheater into a well. Alternatively, the support member may be installedusing a coiled tubing unit including any unit known in the art. Theheaters may be un-spooled and connected to the support as the support isinserted into the well. The electric heater and the support member maybe un-spooled from the spooling assemblies. Spacers may be coupled tothe support member and the heater along a length of the support member.Additional spooling assemblies may be used for additional electricheater elements.

In an embodiment, the support member may be installed using standard oilfield operations and welding different sections of support. Welding maybe done by using orbital welding. For example, a first section of thesupport member may be disposed into the well. A second section (e.g., ofsubstantially similar length) may be coupled to the first section in thewell. The second section may be coupled by welding the second section tothe first section. An orbital welder disposed at the wellhead may beconfigured to weld the second section to the first section. This processmay be repeated with subsequent sections coupled to previous sectionsuntil a support of desired length is within the well.

FIG. 18 illustrates a cross-sectional view of one embodiment of awellhead coupled, e.g., to overburden casing 541. Flange 590 c may becoupled to, or may be a part of, wellhead 590. Flange 590 c may be, forexample, carbon steel, stainless steel or any other commerciallyavailable suitable sealing material. Flange 590 c may be sealed witho-ring 590 f, or any other sealing mechanism. Thermocouples 590 g may beprovided into wellhead 590 through flange 590 c. Thermocouples 590 g maymeasure a temperature on or proximate to support member 564 within theheated portion of the well. Support member 564 may be coupled to flange590 c. Support member 564 may be configured to support one or moreinsulated conductor heaters as described herein. Support member 564 maybe sealed in flange 590 c by welds 590 h. Alternately, support member564 may be sealed by any method known in the art.

Power conductor 590 a may be coupled to a lead-in cable and/or aninsulated conductor heater. Power conductor 590 a may be configured toprovide electrical energy to the insulated conductor heater. Powerconductor 590 a may be sealed in sealing flange 590 d. Sealing flange590 d may be sealed by compression seals or o-rings 590 e. Powerconductor 590 a may be coupled to support member 564 with band 590 i.Band 590 i may include a rigid and corrosion resistant material such asstainless steel. Wellhead 590 may be sealed with weld 590 h such thatfluid may be substantially inhibited from escaping the formation throughwellhead 590. Lift bolt 590 j may be configured to lift wellhead 590 andsupport member 564. Wellhead 590 may also include a pressure controlvalve. Compression fittings 590 k may serve to seal power cable 590 aand compression fittings 590 l may serve to seal thermocouple 590 g.These seals inhibit fluids from escaping the formation. The pressurecontrol valve may be configured to control a pressure within an openingin which support member 564 may be disposed.

In an embodiment, a control system may be configured to controlelectrical power supplied to an insulated conductor heater. Powersupplied to the insulated conductor heater may be controlled with anyappropriate type of controller. For alternating current, the controllermay, for example, be a tapped transformer. Alternatively, the controllermay be a zero crossover electrical heater firing SCR (silicon controlledrectifier) controller. Zero crossover electrical heater firing controlmay be achieved by allowing full supply voltage to the insulatedconductor heater to pass through the insulated conductor heater for aspecific number of cycles, starting at the “crossover,” where aninstantaneous voltage may be zero, continuing for a specific number ofcomplete cycles, and discontinuing when the instantaneous voltage againmay cross zero. A specific number of cycles may be blocked, allowingcontrol of the heat output by the insulated conductor heater. Forexample, the control system may be arranged to block fifteen and/ortwenty cycles out of each sixty cycles that may be supplied by astandard 60 Hz alternating current power supply. Zero crossover firingcontrol may be advantageously used with materials having low temperaturecoefficient materials. Zero crossover firing control may substantiallyinhibit current spikes from occurring in an insulated conductor heater.

FIG. 19 illustrates an embodiment of a conductor-in-conduit heaterconfigured to heat a section of a hydrocarbon containing formation.Conductor 580 may be disposed in conduit 582. Conductor 580 may be a rodor conduit of electrically conductive material. A conductor 580 may havea low resistance section 584 at both the top and the bottom of theconductor 580 in order to generate less heating in these sections 584.The substantially low resistance section 584 may be due to a greatercross-sectional area of conductor 580 in that section. For example,conductor 580 may be a 304 or 310 stainless steel rod with a diameter ofapproximately 2.8 cm. The diameter and wall thickness of conductor 580may vary, however, depending on, for example, a desired heating rate ofthe hydrocarbon containing formation. Conduit 582 may include anelectrically conductive material. For example, conduit 582 may be a 304or 310 stainless steel pipe having a diameter of approximately 7.6 cmand a thickness of approximately schedule 40. Conduit 582 may bedisposed in opening 514 in formation 516. Opening 514 may have adiameter of at least approximately 5 cm. The diameter of the opening mayvary, however, depending on, for example, a desired heating rate in theformation and/or a diameter of conduit 582. For example, a diameter ofthe opening may be from about 10 cm to about 13 cm. Larger diameteropenings may also be used. For example, a larger opening may be used ifmore than one conductor is to be placed within a conduit.

Conductor 580 may be centered in conduit 582 through centralizer 581.Centralizer 581 may electrically isolate conductor 580 from cinduit 582.In addition, centralizer 581 may be configured to locate conductor 580within conduit 582. Centralizer 581 may be made of a ceramic material ora combination of ceramic and metallic materials. More than onecentralizer 581 may be configured to substantially inhibit deformationof conductor 580 in conduit 582 during use. More than one centralizer581 may be spaced at intervals between approximately 0.5 m andapproximately 3 m along conductor 580. Centralized 581 may

As depicted in FIG. 20, sliding connector 583 may couple an end ofconductor 580 disposed proximate a lowermost surface of conduit 582.Sliding connector 583 allows for differential thermal expansion betweenconductor 580 and conduit 582. Sliding connector 583 is attached to aconductor 580 located at the bottom of the well at a low resistancesection 584 which may have a greater cross-sectional area. The lowerresistance of section 584 allows the sliding connector to operate attemperatures no greater than about 90° C. In this manner, corrosion ofthe sliding connector components is minimized and therefore contactresistance between sliding connector 583 and conduit 582 is alsominimized. Sliding connector 583 may be configured as shown in FIG. 20and as described in any of the embodiments herein. The substantially lowresistance section 584 of the conductor 580 may couple conductor 580 towellhead 690 as depicted in FIG. 19. Wellhead 690 may be configured asshown in FIG. 21 and as described in any of the embodiments herein. Asdepicted in FIG. 19, electrical current may be applied to conductor 580from power cable 585 through a low resistance section 584 of theconductor 580. Electrical current may pass from conductor 580 throughsliding connector 583 to conduit 582. Conduit 582 may be electricallyinsulated from overburden casing 541 and from wellhead 690 to returnelectrical current to power cable 585. Heat may be generated inconductor 580 and conduit 582. The generated heat may radiate withinconduit 582 and opening 514 to heat at least a portion of formation 516.As an example, a voltage of about 330 volts and a current of about 795amps may be supplied to conductor 580 and conduit 582 in a 229 m (750ft) heated section to generate about 1150 watts/meter of conductor 580and conduit 582.

Overburden conduit 541 may be disposed in overburden 540 of formation516. Overburden conduit 541 may in some embodiments be surrounded bymaterials that may substantially inhibit heating of overburden 540. Asubstantially low resistance section 584 of a conductor 580 may beplaced in overburden conduit 541. The substantially low resistancesection 584 of conductor 580 may be made of, for example, carbon steel.The substantially low resistance section 584 may have a diameter betweenabout 2 cm to about 5 cm or, for example, a diameter of about 4 cm. Asubstantially low resistance section 584 of conductor 580 may becentralized within overburden conduit 541 using centralizers 581.Centralizers 581 may be spaced at intervals of approximately 6 m toapproximately 12 m or, for example, approximately 9 m alongsubstantially low resistance section 584 of conductor 580. Asubstantially low resistance section 584 of conductor 580 may be coupledto conductor 580 using any method known in the art such as arc welding.A substantially low resistance section 584 may be configured to generatelittle and/or substantially no heat in overburden conduit 541. Packingmaterial 542 may be placed between overburden casing 541 and opening514. Packing material 542 may be configured to substantially inhibitfluid from flowing from opening 514 to surface 550 or to inhibit mostheat carrying fluids from flowing from opening 514 to surface 550.

Overburden conduit may include, for example, a conduit of carbon steelhaving a diameter of about 7.6 cm and a thickness of about schedule 40pipe. Cement 544 may include, for example, slag or silica flour, or amixture thereof (e.g., about 1.58 grams per cubic centimeter slag/silicaflour). Cement 544 may extend radially a width of about 5 cm to about 25cm. Cement 544 may also be made of material designed to inhibit flow ofheat into formation 516.

Surface conductor 545 and overburden casing 541 may enclose cement 544and may couple to wellhead 690. Surface conductor 545 may have adiameter of about 10 cm to about 30 cm and more preferably a diameter ofabout 22 cm. Electrically insulating sealing flanges may be configuredto mechanically couple substantially low resistance section 584 ofconductor 580 to wellhead 690 and to electrically couple lowerresistance section 584 to power cable 585. The electrically insulatingsealing flanges may be configured to couple lead-in conductor 585 towellhead 690. For example, lead-in conductor 585 may include a coppercable, wire, or other elongated member. Lead-in conductor 585 mayinclude, however, any material having a substantially low resistance.The lead-in conductor may be clamped to the bottom of the lowresistivity conductor to make electrical contact.

In an embodiment, heat may be generated in or by conduit 582. In thismanner, about 10% to about 30%, or, for example, about 20%, of the totalheat generated by the heater may be generated in or by conduit 582. Bothconductor 580 and conduit 582 may be made of stainless steel. Dimensionsof conductor 580 and conduit 582 may be chosen such that the conductorwill dissipate heat in a range from approximately 650 watts per meter to1650 watts per meter. A temperature in conduit 582 may be approximately480° C. to approximately 815° C. and a temperature in conductor 580 maybe approximately 500° C. to 840° C. Substantially uniform heating of ahydrocarbon containing formation may be provided along a length ofconduit 582 greater than about 300 m or, maybe, greater than about 600m. A length of conduit 582 may vary, however, depending on, for example,a type of hydrocarbon containing formation, a depth of an opening in theformation, and/or a length of the formation desired for treating.

The generated heat may be configured to heat at least a portion of ahydrocarbon containing formation. Heating of at least the portion mayoccur substantially by radiation of the generated heat within an openingin the formation and to a lesser extent by gas conduction. In thismanner, a cost associated with filling the opening with a fillingmaterial to provide conductive heat transfer between the insulatedconductor and the formation may be eliminated. In addition, heattransfer by radiation is generally more efficient than by conduction sothe heaters will generally operate at lower temperatures in an openwellbore. Still another advantage is that the heating assembly will befree to undergo thermal expansion. Yet another advantage is that theheater may be replaceable.

The conductor-in-conduit heater, as described in any of the embodimentsherein, may be installed in opening 514. In an embodiment, theconductor-in-conduit heater may be installed into a well by sections.For example, a first section of the conductor-in-conduit heater may bedisposed into the well. The section may be about 12 m in length. Asecond section (e.g., of substantially similar length) may be coupled tothe first section in the well. The second section may be coupled bywelding the second section to the first section and/or with threadsdisposed on the first and second section. An orbital welder disposed atthe wellhead may be configured to weld the second section to the firstsection. This process may be repeated with subsequent sections coupledto previous sections until a heater of desired length may be disposed inthe well. In some embodiments, three sections may be coupled prior tobeing disposed in the well. The three sections may be coupled bywelding. The three sections may have a length of about 12.2 m each. Theresulting 37 m section may be lifted vertically by a crane at thewellhead. The three sections may be coupled to three additional sectionsin the well as described herein. Welding the three sections prior tobeing disposed in the well may reduce a number of leaks and/or faultywelds and may decrease a time required for installation of the heater.

In an alternate embodiment, the conductor-in-conduit heater may bespooled onto a spooling assembly. The spooling assembly may be mountedon a transportable structure. The transportable structure may betransported to a well location. The conductor-in-conduit heater may beun-spooled from the spooling assembly into the well.

FIG. 20 illustrates an embodiment of a sliding connector. Slidingconnector 583 may include scraper 593 that may abut an inner surface ofconduit 582 at point 595. Scraper 593 may include any metal orelectrically conducting material (e.g., steel or stainless steel).Centralizer 591 may couple to conductor 580. In some embodiments,conductor 580 may have a substantially low resistance section 584, dueto an increased thickness, substantially around a location of slidingconnector 583. Centralizer 591 may include any electrically conductingmaterial (e.g., a metal or metal alloy). Centralizer 591 may be coupledto scraper 593 through spring bow 592. Spring bow 592 may include anymetal or electrically conducting material (e.g., copper-berylliumalloy). Centralizer 591, spring bow 592, and/or scraper 593 may becoupled through any welding method known in the art. Sliding connector583 may electrically couple the substantially low resistance section 584of conductor 580 to conduit 582 through centralizer 591, spring bow 592,and/or scraper 593. During heating of conductor 580, conductor 580 mayexpand at a substantially different rate than conduit 582. For example,point 594 on conductor 580 may move relative to point 595 on conduit 582during heating of conductor 580. Scraper 593 may maintain electricalcontact with conduit 582 by sliding along surface of conduit 582.Several sliding connectors may be used for redundancy and to reduce thecurrent at each scraper. In addition, a thickness of conduit 582 may beincreased for a length substantially adjacent to sliding connector 583to substantially reduce heat generated in that portion of the conduit582. The length of conduit 582 with increased thickness may be, forexample, approximately 6 m.

FIG. 21 illustrates another embodiment of a wellhead. Wellhead 690 maybe coupled to electrical junction box 690 a by flange 690 n or any othersuitable mechanical device. Electrical junction box 690 a may beconfigured to control power (current and voltage) supplied to anelectric heater. The electric heater may be a conductor-in-conduitheater as described herein. Flange 690 n may include, for example,stainless steel or any other suitable sealing material. Conductor 690 bmay be disposed in flange 690 n and may electrically couple overburdencasing 541 to electrical junction box 690 a. Conductor 690 b may includeany metal or electrically conductive material (e.g., copper).Compression seal 690 c may seal conductor 690 b at an inner surface ofelectrical junction box 690 a.

Flange 690 n may be sealed with metal o-ring 690 d. Conduit 690 f, whichmay be, e.g. a pipe, may couple flange 690 n to flange 690 m. Flange 690m may couple to overburden casing 541. Flange 690 m may be sealed witho-ring 690 g (e.g., metal o-ring or steel o-ring). The substantially lowresistance section 584 of the conductor (e.g., conductor 580) may coupleto electrical junction box 690 a. The substantially low resistancesection 584 may be passed through flange 690 n and may be sealed inflange 690 n with o-ring assembly 690 p. Assemblies 690 p are designedto insulate the substantially low resistance section 584 of conductor580 from flange 690 n and flange 690 m. O-ring assembly 690 c may bedesigned to electrically insulate conductor 690 b from flange 690 m andjunction box 690 a. Centralizer 581 may couple to low resistance section584. Electrically insulating centralizer 581 may have characteristics asdescribed in any of the embodiments herein. Thermocouples 690 i may becoupled to thermocouple flange 690 q with connectors 690 h and wire 690j. Thermocouples 690 i may be enclosed in an electrically insulatedsheath (e.g., a metal sheath). Thermocouples 690 i may be sealed inthermocouple flange 690 q with compression seals 690 k. Thermocouples690 i may be used to monitor temperatures in the heated portiondownhole.

FIG. 22 illustrates a perspective view of an embodiment of a centralizerin, e.g., conduit 582. Electrical insulator 581 a may be disposed onconductor 580. Insulator 581 a may be made of, for example, aluminumoxide or any other electrically insulating material that may beconfigured for use at high temperatures. A location of insulator 581 aon the conductor 580 may be maintained by disc 581 d. Disc 581 d may bewelded to conductor 580. Spring bow 581 c may be coupled to insulator581 a by disc 581 b. Spring bow 581 c and disc 581 b may be made ofmetals such as 310 stainless steel and any other thermally conductingmaterial that may be configured for use at high temperatures.Centralizer 581 may be arranged as a single cylindrical member disposedon conductor 580. Centralizer 581 may be arranged as twohalf-cylindrical members disposed on conductor 580. The twohalf-cylindrical members may be coupled to conductor 580 by band 581 e.Band 581 e may be made of any material configured for use at hightemperatures (e.g., steel).

FIG. 23a illustrates a cross-sectional view of an embodiment of acentralizer 581 disposed on conductor 580. FIG. 23b illustrates aperspective view of the embodiment shown in FIG. 23a. Centralizer 581may be made of any suitable electrically insulating material that maysubstantially withstand high voltage at high temperatures. Examples ofsuch materials may be aluminum oxide and/or Macor. Discs 581 d maymaintain positions of centralizer 581 relative to conductor 580. Discs581 d may be metal discs welded to conductor 580. Discs 581 d may betack-welded to conductor 580. Centralizer 581 may substantiallyelectrically insulate conductor 580 from conduit 582.

In an embodiment, a conduit may be pressurized with a fluid to balance apressure in the conduit with a pressure in an opening. In this manner,deformation of the conduit may be substantially inhibited. A thermallyconductive fluid may be configured to pressurize the conduit. Thethermally conductive fluid may increase heat transfer within theconduit. The thermally conductive fluid may include a gas such ashelium, nitrogen, air, or mixtures thereof. A pressurized fluid may alsobe configured to pressurize the conduit such that the pressurized fluidmay inhibit arcing between the conductor and the conduit. If air and/orair mixtures are used to pressurize the conduit, the air and/or airmixtures may react with materials of the conductor and the conduit toform an oxide on a surface of the conductor and the conduit such thatthe conductor and the conduit are at least somewhat more resistant tocorrosion.

An emissivity of a conductor and/or a conduit may be increased. Forexample, a surface of the conductor and/or the conduit may be roughenedto increase the emissivity. Blackening the surface of the conductorand/or the conduit may also increase the emissivity. Alternatively,oxidation of the conductor and/or the conduit prior to installation maybe configured to increase the emissivity. The conductor and/or theconduit may also be oxidized by heating the conductor and/or the conduitin the presence of an oxidizing fluid in the conduit and/or in anopening in a hydrocarbon containing formation. Another alternative forincreasing the emissivity may be to anodize the conductor and/or theconduit such that the surface may be roughened and/or blackened.

In another embodiment, a perforated tube may be placed in the openingformed in the hydrocarbon containing formation proximate to and externalthe first conduit. The perforated tube may be configured to removefluids formed in the opening. In this manner, a pressure may bemaintained in the opening such that deformation of the first conduit maybe substantially inhibited and the pressure in the formation near theheaters may be reduced. The perforated tube may also be used to increaseor decrease pressure in the formation by addition or removal of a fluidor fluids from the formation. This may allow control of the pressure inthe formation and control of quality of produced hydrocarbons.Perforated tubes may be used for pressure control in all describedembodiments of heat sources using an open hole configuration. Theperforated tube may also be configured to inject gases to upgradehydrocarbon properties in situ; for example, hydrogen gas may beinjected under elevated pressure.

FIG. 24 illustrates an alternative embodiment of a conductor-in-conduitheater configured to heat a section of a hydrocarbon containingformation. Second conductor 586 may be disposed in conduit 582 inaddition to conductor 580. Conductor 580 may be configured as describedherein. Second conductor 586 may be coupled to conductor 580 usingconnector 587 located near a lowermost surface of conduit 582. Secondconductor 586 may be configured as a return path for the electricalcurrent supplied to conductor 580. For example, second conductor 586 mayreturn electrical current to wellhead 690 through second substantiallylow resistance conductor 588 in overburden casing 541. Second conductor586 and conductor 580 may be configured of an elongated conductivematerial. Second conductor 586 and conductor 580 may be, for example, astainless steel rod having a diameter of approximately 2.4 cm. Connector587 may be flexible. Conduit 582 may be electrically isolated fromconductor 580 and second conductor 586 using centralizers 581.Overburden casing 541, cement 544, surface conductor 545, and packingmaterial 542 may be configured as described in the embodiment shown inFIG. 19. Advantages of this embodiment include the absence of a slidingcontactor, which may extend the life of the heater, and the isolation ofall applied power from formation 516.

In another embodiment, a second conductor may be disposed in a secondconduit, and a third conductor may be disposed in a third conduit. Thesecond opening may be different from the opening for the first conduit.The third opening may be different from the opening for the firstconduit and the second opening. For example, each of the first, second,and third openings may be disposed in substantially different welllocations of the formation and may have substantially similardimensions. The first, second, and third conductors may be configured asdescribed herein. The first, second, and third conductors may beelectrically coupled in a 3-phase Y electrical configuration. The outerconduits may be connected together or may be connected to the ground.The 3-phase Y electrical configuration may provide a safer, moreefficient method to heat a hydrocarbon containing formation than using asingle conductor. The first, second, and/or third conduits may beelectrically isolated from the first, second, and third conductors,respectively. Dimensions of each conductor and each conduit may beconfigured such that each conductor may generate heat of approximately650 watts per meter of conductor to approximately 1650 watts per meterof conductor. In an embodiment, a first conductor and a second conductorin a conduit may be coupled by a flexible connecting cable. The bottomof the first and second conductor may be enlarged to create lowresistance sections, and thus generate less heat. In this manner, theflexible connector may be made of, for example, stranded copper coveredwith rubber insulation.

In an embodiment, a first conductor and a second conductor may becoupled to at least one sliding connector within a conduit. The slidingconnector may be configured as described herein. For example, such asliding connector may be configured to generate less heat than the firstconductor or the second conductor. The conduit may be electricallyisolated from the first conductor, second conductor, and/or the slidingconnector. The sliding connector may be placed in a location within thefirst conduit where substantially less heating of the hydrocarboncontaining formation may be required.

In an embodiment, a thickness of a section of a conduit may be increasedsuch that substantially less heat may be transferred (e.g., radiated)along the section of increased thickness. The section with increasedthickness may preferably be formed along a length of the conduit whereless heating of the hydrocarbon containing formation may be required.

In an embodiment, the conductor may be formed of sections of variousmetals that are welded together. The cross sectional area of the variousmetals may be selected to allow the resulting conductor to be long, tobe creep resistant at high operating temperatures, and/or to dissipatesubstantially the same amount of heat per unit length along the entirelength of the conductor. For example, a first section may be made of acreep resistant metal (such as, but not limited to, Inconel 617 orHR120) and a second section of the conductor may be made of 304stainless steel. The creep resistant first section may help to supportthe second section. The cross sectional area of the first section may belarger than the cross sectional area of the second section. The largercross sectional area of the first section may allow for greater strengthof the first section. Higher resistivity properties of the first sectionmay allow the first section to dissipate the same amount of heat perunit length as the smaller cross sectional area second section.

In some embodiments, the cross sectional area and/or the metal used fora particular section may be chosen so that a particular section providesgreater (or lesser) heat dissipation per unit length than an adjacentsection. More heat may be provided near an interface between ahydrocarbon layer and a non-hydrocarbon layer (e.g., the overburden andthe hydrocarbon containing formation) to counteract end effects andallow for more uniform heat dissipation into the hydrocarbon containingformation. A higher heat dissipation may also be located at a lower endof an elongated member to counteract end effects and allow for moreuniform heat dissipation.

In an embodiment, an elongated member may be disposed within an opening(e.g., an open wellbore) in a hydrocarbon containing formation. Theopening may preferably be an uncased opening in the hydrocarboncontaining formation. The opening may have a diameter of at leastapproximately 5 cm or, for example, approximately 8 cm. The diameter ofthe opening may vary, however, depending on, for example, a desiredheating rate in the formation. The elongated member may be a length(e.g., a strip) of metal or any other elongated piece of metal (e.g., arod). The elongated member may include stainless steel. The elongatedmember, however, may also include any conductive material configurableto generate heat to sufficiently heat a portion of the formation and tosubstantially withstand a corresponding temperature within the opening,for example, it may be configured to withstand corrosion at thetemperature within the opening.

An elongated member may be a bare metal heater. “Bare metal” refers to ametal that does not include a layer of electrical insulation, such asmineral insulation, that is designed to provide electrical insulationfor the metal throughout an operating temperature range of the elongatedmember. Bare metal may encompass a metal that includes a corrosioninhibiter such as a naturally occurring oxidation layer, an appliedoxidation layer, and/or a film. Bare metal includes metal with polymericor other types of electrical insulation that cannot retain electricalinsulating properties at typical operating temperature of the elongatedmember. Such material may be placed on the metal and may be thermallydegraded during use of the heater.

An elongated member may have a length of about 650 meters. Longerlengths may be achieved using sections of high strength alloys, but suchelongated members may be expensive. In some embodiments, an elongatedmember may be supported by a plate in a wellhead. The elongated membermay include sections of different conductive materials that are weldedtogether end-to-end. A large amount of electrically conductive weldmaterial may be used to couple the separate sections together toincrease strength of the resulting member and to provide a path forelectricity to flow that will not result in arcing and/or corrosion atthe welded connections. The different conductive materials may includealloys with a high creep resistance. The sections of differentconductive materials may have varying diameters to ensure uniformheating along the elongated member. A first metal that has a highercreep resistance than a second metal typically has a higher resistivitythan the second metal. The difference in resistivities may allow asection of larger cross sectional area, more creep resistant, firstmetal to dissipate the same amount of heat as a section of smaller crosssectional area, second metal. The cross sectional areas of the twodifferent metals may be tailored to result in substantially the sameamount of heat dissipation in two welded together sections of themetals. The conductive materials may include, but are not limited to,617 Inconel, HR-120, 316 stainless steel, and 304 stainless steel. Forexample, an elongated member may have a 60 meter section of 617 Inconel,60 meter section of HR-120, and 150 meter section of 304 stainlesssteel. In addition, the elongated member may have a low resistancesection that may run from the wellhead through the overburden. This lowresistance section may decrease the heating within the formation fromthe wellhead through the overburden. The low resistance section may bethe result of, for example, choosing a substantially electricallyconductive material and/or increasing the cross-sectional area availablefor electrical conduction.

Alternately, a support member may extend through the overburden, and thebare metal elongated member or members may be coupled to a plate, acentralizer or other type of support member near an interface betweenthe overburden and the hydrocarbon formation. A low resistivity cable,such as a stranded copper cable, may extend along the support member andmay be coupled to the elongated member or members. The copper cable maybe coupled to a power source that supplies electricity to the elongatedmember or members.

FIG. 25 illustrates an embodiment of a plurality of elongated membersconfigured to heat a section of a hydrocarbon containing formation. Twoor more (e.g., four) elongated members 600 may be supported by supportmember 604. Elongated members 600 may be coupled to support member 604using insulated centralizers 602. Support member 604 may be a tube orconduit. Support member 604 may also be a perforated tube. Supportmember 604 may be configured to provide a flow of an oxidizing fluidinto opening 514. Support member 604 may have a diameter between about1.2 cm to about 4 cm and more preferably about 2.5 cm. Support member604, elongated members 600, and insulated centralizers 602 may bedisposed in opening 514 in formation 516. Insulated centralizers 602 maybe configured to maintain a location of elongated members 600 on supportmember 604 such that lateral movement of elongated members 600 may besubstantially inhibited at temperatures high enough to deform supportmember 604 or elongated members 600. Insulated centralizers 602 may be acentralizer as described herein. Elongated members 600, in someembodiments, may be metal strips of about 2.5 cm wide and about 0.3 cmthick stainless steel. Elongated members 600, however, may also includea pipe or a rod formed of a conductive material. Electrical current maybe applied to elongated members 600 such that elongated members 600 maygenerate heat due to electrical resistance.

Elongated members 600 may be configured to generate heat ofapproximately 650 watts per meter of elongated members 600 toapproximately 1650 watts per meter of elongated members 600. In thismanner, elongated members 600 may be at a temperature of approximately480° C. to approximately 815° C. Substantially uniform heating of ahydrocarbon containing formation may be provided along a length ofelongated members 600 greater than about 305 m or, maybe, greater thanabout 610 m. A length of elongated members 600 may vary, however,depending on, for example, a type of hydrocarbon containing formation, adepth of an opening in the formation, and/or a length of the formationdesired for treating

Elongated members 600 may be electrically coupled in series. Electricalcurrent may be supplied to elongated members 600 using lead-in conductor572. Lead-in conductor 572 may be further configured as describedherein. Lead-in conductor 572 may be coupled to wellhead 690. Electricalcurrent may be returned to wellhead 690 using lead-out conductor 606coupled to elongated members 600. Lead-in conductor 572 and lead-outconductor 606 may be coupled to wellhead 690 at surface 550 through asealing flange located between wellhead 690 and overburden 540. Thesealing flange may substantially inhibit fluid from escaping fromopening 514 to surface 550. Lead-in conductor 572 and lead-out conductor606 may be coupled to elongated members using a cold pin transitionconductor. The cold pin transition conductor may include an insulatedconductor of substantially low resistance such that substantially noheat may be generated by the cold pin transition conductor. The cold pintransition conductor may be coupled to lead-in conductor 572, lead-outconductor 606, and/or elongated members 600 by any splicing or weldingmethods known in the art. The cold pin transition conductor may providea temperature transition between lead-in conductor 572, lead-outconductor 606, and/or elongated members 600. The cold pin transitionconductor may be further configured as described in any of theembodiments herein. Lead-in conductor 572 and lead-out conductor 606 maybe made of low resistance conductors such that substantially no heat maybe generated from electrical current passing through lead-in conductor572 and lead-out conductor 606.

Weld beads may be placed beneath the centralizers 602 on the supportmember 604 to fix the position of the centralizers. Weld beads may beplaced on the elongated members 600 above the uppermost centralizer tofix the position of the elongated members relative to the support member(other types of connecting mechanisms may also be used). When heated,the elongated member may thermally expand downwards. The elongatedmember may be formed of different metals at different locations along alength of the elongated member to allow relatively long lengths to beformed. For example, a “U” shaped elongated member may include a firstlength formed of 310 stainless steel, a second length formed of 304stainless steel welded to the first length, and a third length formed of310 stainless steel welded to the second length. 310 stainless steel ismore resistive than 304 stainless steel and may dissipate approximately25% more energy per unit length than 304 stainless steel of the samedimensions. 310 stainless steel may be more creep resistant than 304stainless steel. The first length and the third length may be formedwith cross sectional areas that allow the first length and third lengthsto dissipate as much heat as a smaller cross area section of 304stainless steel. The first and third lengths may be positioned close tothe wellhead 690. The use of different types of metal may allow theformation of long elongated members. The different metals may be, butare not limited to, 617 Inconel, HR120, 316 stainless steel, 310stainless steel, and 304 stainless steel.

Packing material 542 may be placed between overburden casing 541 andopening 514. Packing material 542 may be configured to inhibit fluidflowing from opening 514 to surface 550 and to inhibit correspondingheat losses towards the surface. Packing material 542 may be furtherconfigured as described herein. Overburden casing 541 may be placed incement 544 in overburden 540 of formation 516. Overburden casing 541 maybe further configured as described herein. Surface conductor 545 may bedisposed in cement 544. Surface conductor 545 may be configured asdescribed herein. Support member 604 may be coupled to wellhead 690 atsurface 550 of formation 516. Centralizer 581 may be configured tomaintain a location of support member 604 within overburden casing 541.Centralizer 581 may be further configured as described herein.Electrical current may be supplied to elongated members 600 to generateheat. Heat generated from elongated members 600 may radiate withinopening 514 to heat at least a portion of formation 516.

The oxidizing fluid may be provided along a length of the elongatedmembers 600 from oxidizing fluid source 508. The oxidizing fluid mayinhibit carbon deposition on or proximate to the elongated members. Forexample, the oxidizing fluid may react with hydrocarbons to form carbondioxide, which may be removed from the opening. Openings 605 in supportmember 604 may be configured to provide a flow of the oxidizing fluidalong the length of elongated members 600. Openings 605 may be criticalflow orifices as configured and described herein. Alternatively, a tubemay be disposed proximate to elongated members 600 to control thepressure in the formation as described in above embodiments. In anotherembodiment, a tube may be disposed proximate to elongated members 600 toprovide a flow of oxidizing fluid into opening 514. Also, at least oneof elongated members 600 may include a tube having openings configuredto provide the flow of oxidizing fluid. Without the flow of oxidizingfluid, carbon deposition may occur on or proximate to elongated members600 or on insulated centralizers 602, thereby causing shorting betweenelongated members 600 and insulated centralizers 602 or hot spots alongelongated members 600. The oxidizing fluid may be used to react with thecarbon in the formation as described herein. The heat generated byreaction with the carbon may complement or supplement the heat generatedelectrically.

In an embodiment, a plurality of elongated members may be supported on asupport member disposed in an opening. The plurality of elongatedmembers may be electrically coupled in either a series or parallelconfiguration. A current and voltage applied to the plurality ofelongated members may be selected such that the cost of the electricalsupply of power at the surface in conjunction with the cost of theplurality of elongated members may be minimized. In addition, anoperating current and voltage may be chosen to optimize a cost of inputelectrical energy in conjunction with a material cost of the elongatedmembers. The elongated members may be configured to generate and radiateheat as described herein. The elongated members may be installed inopening 514 as described herein.

In an embodiment, a bare metal elongated member may be formed in a “U”shape (or hairpin) and the member may be suspended from a wellhead orfrom a positioner placed at or near an interface between the overburdenand the formation to be heated. In certain embodiments, the bare metalheaters are formed of rod stock. Cylindrical, high alumina ceramicelectrical insulators may be placed over legs of the elongated members.Tack welds along lengths of the legs may fix the position of theinsulators. The insulators may inhibit the elongated member fromcontacting the formation or a well casing (if the elongated member isplaced within a well casing). The insulators may also inhibit legs ofthe “U” shaped members from contacting each other. High alumina ceramicelectrical insulators may be purchased from Cooper Industries (Houston,Tex.). In an embodiment, the “U” shaped member may be formed ofdifferent metals having different cross sectional areas so that theelongated members may be relatively long and may dissipate substantiallythe same amount of heat per unit length along the entire length of theelongated member. The use of different welded together sections mayresult in an elongated member that has large diameter sections near atop of the elongated member and a smaller diameter section or sectionslower down a length of the elongated member. For example, an embodimentof an elongated member has two ⅞ inch (2.2 cm) diameter first sections,two ½ inch (1.3 cm) middle sections, and a ⅜ inch (0.95 cm) diameterbottom section that is bent into a “U” shape. The elongated member maybe made of materials with other cross section shapes such as ovals,squares, rectangles, triangles, etc. The sections may be formed ofalloys that will result in substantially the same heat dissipation perunit length for each section.

In some embodiments, the cross sectional area and/or the metal used fora particular section may be chosen so that a particular section providesgreater (or lesser) heat dissipation per unit length than an adjacentsection. More heat dissipation per unit length may be provided near aninterface between a hydrocarbon layer and a non-hydrocarbon layer (e.g.,the overburden and the hydrocarbon containing formation) to counteractend effects and allow for more uniform heat dissipation into thehydrocarbon containing formation. A higher heat dissipation may also belocated at a lower end of an elongated member to counteract end effectsand allow for more uniform heat dissipation.

FIG. 26 illustrates an embodiment of a surface combustor configured toheat a section of a hydrocarbon containing formation. Fuel fluid 611 maybe provided into burner 610 through conduit 617. An oxidizing fluid maybe provided into burner 610 from oxidizing fluid source 508. Fuel fluid611 may be oxidized with the oxidizing fluid in burner 610 to formoxidation products 613. Fuel fluid 611 may include, for example,hydrogen. Fuel fluid 611 may also include methane or any otherhydrocarbon fluids. Burner 610 may be located external to formation 516or within an opening 614 in the hydrocarbon containing formation 516.Flame 618 may be configured to heat fuel fluid 611 to a temperaturesufficient to support oxidation in burner 610. Flame 618 may beconfigured to heat fuel fluid 611 to a temperature of about 1425° C.Flame 618 may be coupled to an end of conduit 617. Flame 618 may be apilot flame. The pilot flame may be configured to burn with a small flowof fuel fluid 611. Flame 618 may, however, be an electrical ignitionsource.

Oxidation products 613 may be provided into opening 614 within innerconduit 612 coupled to burner 610. Heat may be transferred fromoxidation products 613 through outer conduit 615 into opening 614 and toformation 516 along a length of inner conduit 612. Therefore, oxidationproducts 613 may substantially cool along the length of inner conduit612. For example, oxidation products 613 may have a temperature of about870° C. proximate top of inner conduit 612 and a temperature of about650° C. proximate bottom of inner conduit 612. A section of innerconduit 612 proximate to burner 610 may have ceramic insulator 612 bdisposed on an inner surface of inner conduit 612. Ceramic insulator 612b may be configured to substantially inhibit melting of inner conduit612 and/or insulation 612 a proximate to burner 610. Opening 614 mayextend into the formation a length up to about 550 m below surface 550.

Inner conduit 612 may be configured to provide oxidation products 613into outer conduit 615 proximate a bottom of opening 614. Inner conduit612 may have insulation 612 a. FIG. 27 illustrates an embodiment ofinner conduit 612 with insulation 612 a and ceramic a insulator 612 bdisposed on an inner surface of inner conduit 612. Insulation 612 a maybe configured to substantially inhibit heat transfer between fluids ininner conduit 612 and fluids in outer conduit 615. A thickness ofinsulation 612 a may be varied along a length of inner conduit 612 suchthat heat transfer to formation 516 may vary along the length of innerconduit 612. For example, a thickness of insulation 612 a may be taperedfrom a larger thickness to a lesser thickness from a top portion to abottom portion, respectively, of inner conduit 612 in opening 614. Sucha tapered thickness may provide substantially more uniform heating offormation 516 along the length of inner conduit 612 in opening 614.Insulation 612 a may include ceramic and metal materials. Oxidationproducts 613 may return to surface 550 through outer conduit 615. Outerconduit may have insulation 615 a as depicted in FIG. 26. Insulation 615a may be configured to substantially inhibit heat transfer from outerconduit 615 to overburden 540.

Oxidation products 613 may be provided to an additional burner throughconduit 619 at surface 550. Oxidation products 613 may be configured asa portion of a fuel fluid in the additional burner. Doing so mayincrease an efficiency of energy output versus energy input for heatingformation 516. The additional burner may be configured to provide heatthrough an additional opening in formation 516.

In some embodiments, an electric heater may be configured to provideheat in addition to heat provided from a surface combustor. The electricheater may be, for example, an insulated conductor heater or aconductor-in-conduit heater as described in any of the aboveembodiments. The electric heater may be configured to provide theadditional heat to a hydrocarbon containing formation such that thehydrocarbon containing formation may be heated substantially uniformlyalong a depth of an opening in the formation.

Flameless combustors such as those described in U.S. Pat. No. 5,255,742to Mikus et al. U.S. Pat. No. 5,404.952 to Vinegar et al., U.S. Pat. No.5,862,858 to Wellington et al., and U.S. Pat. No. 5,899,269 toWellington et al., which are incorporated by reference as if fully setforth herein, may be configured to heat a hydrocarbon containingformation.

FIG. 28 illustrates an embodiment of a flameless combustor configured toheat a section of the hydrocarbon containing formation. The flamelesscombustor may include center tube 637 disposed within inner conduit 638.Center tube 637 and inner conduit 638 may be placed within outer conduit636. Outer conduit 636 may be disposed within opening 514 in formation516. Fuel fluid 621 may be provided into the flameless combustor throughcenter tube 637. Fuel fluid 621 may include any of the fuel fluidsdescribed herein. If a hydrocarbon fuel such as methane is utilized, itmay be mixed with steam to prevent coking in center tube 637. Ifhydrogen is used as the fuel, no steam may be required.

Center tube 637 may include flow mechanisms 635 (e.g., flow orifices)disposed within an oxidation region to allow a flow of fuel fluid 621into inner conduit 638. Flow mechanisms 635 may control a flow of fuelfluid 621 into inner conduit 638 such that the flow of fuel fluid 621 isnot dependent on a pressure in inner conduit 638. Flow mechanisms 635may have characteristics as described herein. Oxidizing fluid 623 may beprovided into the combustor through inner conduit 638. Oxidizing fluid623 may be provided from oxidizing fluid source 508. Oxidizing fluid 623may include any of the oxidizing fluids as described in aboveembodiments. Flow mechanisms 635 on center tube 637 may be configured toinhibit flow of oxidizing fluid 623 into center tube 637.

Oxidizing fluid 623 may mix with fuel fluid 621 in the oxidation regionof inner conduit 638. Either oxidizing fluid 623 or fuel fluid 621, or acombination of both, may be preheated external to the combustor to atemperature sufficient to support oxidation of fuel fluid 621. Oxidationof fuel fluid 621 may provide heat generation within outer conduit 636.The generated heat may provide heat to at least a portion of ahydrocarbon containing formation proximate to the oxidation region ofinner conduit 638. Products 625 from oxidation of fuel fluid 621 may beremoved through outer conduit 636 outside inner conduit 638. Heatexchange between the downgoing oxidizing fluid and the upgoingcombustion products in the overburden results in enhanced thermalefficiency. A flow of removed combustion products 625 may be balancedwith a flow of fuel fluid 621 and oxidizing fluid 623 to maintain atemperature above autoignition temperature but below a temperaturesufficient to produce substantial oxides of nitrogen. Also, a constantflow of fluids may provide a substantially uniform temperaturedistribution within the oxidation region of inner conduit 638. Outerconduit 636 may be, for example, a stainless steel tube. In this manner,heating of at least the portion of the hydrocarbon containing formationmay be substantially uniform. As described above, the lower operatingtemperature may also provide a less expensive metallurgical costassociated with the heating system.

Certain heat source embodiments may include an operating system that iscoupled to any of heat sources such by insulated conductors or othertypes of wiring. The operating system may be configured to interfacewith the heat source. The operating system may receive a signal (e.g.,an electromagnetic signal) from a heater that is representative of atemperature distribution of the heat source. Additionally, the operatingsystem may be further configured to control the heat source, eitherlocally or remotely. For example, the operating system may alter atemperature of the heat source by altering a parameter of equipmentcoupled to the heat source. Therefore, the operating system may monitor,alter, and/or control the heating of at least a portion of theformation.

In some embodiments, a heat source as described above may be configuredto substantially operate without a control and/or operating system. Theheat source may be configured to only require a power supply from apower source such as an electric transformer. For example, aconductor-in-conduit heater and/or an elongated member heater mayinclude conductive materials that may be have a thermal property thatself-controls a heat output of the heat source. In this manner, theconductor-in-conduit heater and/or the elongated member heater may beconfigured to operate throughout a temperature range without externalcontrol. A conductive material such as stainless steel may be used inthe heat sources. Stainless steel may have a resistivity that increaseswith temperature, thus, providing a greater heat output at highertemperatures.

Leakage current of any of the heat sources described herein may bemonitored. For example, an increase in leakage current may showdeterioration in an insulated conductor heater. Voltage breakdown in theinsulated conductor heater may cause failure of the heat source.Furthermore, a current and voltage applied to any of the heat sourcesmay also be monitored. The current and voltage may be monitored toassess/indicate resistance in a heat source. The resistance in the heatsource may be configured to represent a temperature in the heat sourcesince the resistance of the heat source may be known as a function oftemperature. Another alternative method may include monitoring atemperature of a heat source with at least one thermocouple placed in orproximate to the heat source. In some embodiments, a control system maymonitor a parameter of the heat source. The control system may alterparameters of the heat source such that the heat source may provide adesired output such as heating rate and/or temperature increase.

In some embodiments, a thermowell may be disposed into an opening in ahydrocarbon containing formation that includes a heat source. Thethermowell may be disposed in an opening that may or may not have acasing. In the opening without a casing, the thermowell may includeappropriate metallurgy and thickness such that corrosion of thethermowell is substantially inhibited. A thermowell and temperaturelogging process, such as that described in U.S. Pat. No. 4,616,705issued to Stegemeier et al., which is incorporated by reference as iffully set forth herein, may be used to monitor temperature. Onlyselected wells may be equipped with thermowells to avoid expensesassociated with installing and operating temperature monitors at eachheat source.

In some embodiments, a heat source may be turned down and/or off afteran average temperature in a formation may have reached a selectedtemperature. Turning down and/or off the heat source may reduce inputenergy costs, substantially inhibit overheating of the formation, andallow heat to substantially transfer into colder regions of theformation.

Certain embodiments include providing heat to a first portion of ahydrocarbon containing formation from one or more heat sources. Inaddition, certain embodiments may include producing formation fluidsfrom the first portion, and maintaining a second portion of theformation in a substantially unheated condition. The second portion maybe substantially adjacent to the first portion of the formation. In thismanner, the second portion may provide structural strength to theformation. Furthermore, heat may also be provided to a third portion ofthe formation. The third portion may be substantially adjacent to thesecond portion and/or laterally spaced from the first portion. Inaddition, formation fluids may be produced from the third portion of theformation. In this manner, a processed formation may have a pattern thatmay resemble, for example, a striped or checkerboard pattern withalternating heated and unheated portions.

Additional portions of the formation may also include such alternatingheated and unheated portions. In this manner, such patterned heating ofa hydrocarbon containing formation may maintain structural strengthwithin the formation. Maintaining structural strength within ahydrocarbon containing formation may substantially inhibit subsidence.Subsidence of a portion of the formation being processed may decrease apermeability of the processed portion due to compaction. In addition,subsidence may decrease the flow of fluids in the formation, which mayresult in a lower production of formation fluids.

A pyrolysis temperature range may depend on specific types ofhydrocarbons within the formation. A pyrolysis temperature range mayinclude temperatures, for example, between approximately 250° C. andabout 900° C. Alternatively, a pyrolysis temperature range may includetemperatures between about 250° C. to about 400° C. For example, amajority of formation fluids may be produced within a pyrolysistemperature range from about 250° C. to about 400° C. If a hydrocarboncontaining formation is heated throughout the entire pyrolysis range,the formation may produce only small amounts of hydrogen towards theupper limit of the pyrolysis range. After all of the available hydrogenhas been depleted, little fluid production from the formation wouldoccur.

Temperature (and average temperatures) within a heated hydrocarboncontaining formation may vary, depending on, for example, proximity to aheat source, thermal conductivity and thermal diffusivity of theformation, type of reaction occurring, type of hydrocarbon containingformation, and the presence of water within the hydrocarbon containingformation. A temperature within the hydrocarbon containing formation maybe assessed using a numerical simulation model. The numerical simulationmodel may assess and/or calculate a subsurface temperature distribution.In addition, the numerical simulation model may include assessingvarious properties of a subsurface formation under the assessedtemperature distribution.

For example, the various properties of the subsurface formation mayinclude, but are not limited to, thermal conductivity of the subsurfaceportion of the formation and permeability of the subsurface portion ofthe formation. The numerical simulation model may also include assessingvarious properties of a fluid formed within a subsurface formation underthe assessed temperature distribution. For example, the variousproperties of a formed fluid may include, but are not limited to, acumulative volume of a fluid formed at a subsurface of the formation,fluid viscosity, fluid density, and a composition of the fluid formed ata subsurface of the formation. Such a simulation may be used to assessthe performance of commercial-scale operation of a small-scale fieldexperiment as described herein. For example, a performance of acommercial-scale development may be assessed based on, but not limitedto, a total volume of product that may be produced from acommercial-scale operation.

In some embodiments, an in situ conversion process may increase atemperature or average temperature within a hydrocarbon containingformation. A temperature or average temperature increase (ΔT) in aspecified volume (V) of the hydrocarbon containing formation may beassessed for a given heat input rate (q) over time (t) by the followingequation:${\Delta \quad T} = \frac{\sum( {q*t} )}{C_{V}*\rho_{B}*V}$

In this equation, an average heat capacity of the formation (C_(V)) andan average bulk density of the formation (ρ_(B)) may be estimated ordetermined using one or more samples taken from the hydrocarboncontaining formation.

In alternate embodiments, an in situ conversion process may includeheating a specified volume to a pyrolysis temperature or averagepyrolysis temperature. Heat input rate (q) during a time (t) required toheat the specified volume (V) to a desired temperature increase (ΔT) maybe determined or assessed using the following equation:Σq*t=ΔT*C_(V)*ρ_(B)*V . In this equation, an average heat capacity ofthe formation (C_(V)) and an average bulk density of the formation(ρ_(B)) may be estimated or determined using one or more samples takenfrom the hydrocarbon containing formation.

It is to be understood that the above equations can be used to assess orestimate temperatures, average temperatures (e.g., over selectedsections of the formation), heat input, etc. Such equations do not takeinto account other factors (such as heat losses), which would also havesome effect on heating and temperatures assessments. However suchfactors can ordinarily be addressed with correction factors, as iscommonly done in the art.

In some embodiments, a portion of a hydrocarbon containing formation maybe heated at a heating rate in a range from about 0.1° C./day to about50° C./day. Alternatively, a portion of a hydrocarbon containingformation may be heated at a heating rate in a range of about 0.1°C./day to about 10° C./day. For example, a majority of hydrocarbons maybe produced from a formation at a heating rate within a range of about0.1° C./day to about 10° C./day. In addition, a hydrocarbon containingformation may be heated at a rate of less than about 0.7° C./day througha significant portion of a pyrolysis temperature range. The pyrolysistemperature range may include a range of temperatures as described inabove embodiments. For example, the heated portion may be heated at sucha rate for a time greater than 50% of the time needed to span thetemperature range, more than 75% of the time needed to span thetemperature range, or more than 90% of the time needed to span thetemperature range.

A rate at which a hydrocarbon containing formation is heated may affectthe quantity and quality of the formation fluids produced from thehydrocarbon containing formation. For example, heating at high heatingrates, as is the case when a Fischer Assay is conducted, may produce alarger quantity of condensable hydrocarbons from a hydrocarboncontaining formation. The products of such a process, however, may be ofa significantly lower quality than when heating using heating rates lessthan about 10° C./day. Heating at a rate of temperature increase lessthan approximately 10° C./day may allow pyrolysis to occur within apyrolysis temperature range in which production of undesirable productsand tars may be reduced. In addition, a rate of temperature increase ofless than about 3° C./day may further increase the quality of theproduced condensable hydrocarbons by further reducing the production ofundesirable products and further reducing production of tars within ahydrocarbon containing formation.

In some embodiments, controlling temperature within a hydrocarboncontaining formation may involve controlling a heating rate within theformation. For example, controlling the heating rate such that theheating rate may be less than approximately 3° C./day may provide bettercontrol of a temperature within the hydrocarbon containing formation.

An in situ process for hydrocarbons may include monitoring a rate oftemperature increase at a production well. A temperature within aportion of a hydrocarbon containing formation, however, may be measuredat various locations within the portion of the hydrocarbon containingformation. For example, an in situ process may include monitoring atemperature of the portion at a midpoint between two adjacent heatsources. The temperature may be monitored over time. In this manner, arate of temperature increase may also be monitored. A rate oftemperature increase may affect a composition of formation fluidsproduced from the formation. As such, a rate of temperature increase maybe monitored, altered and/or controlled, for example, to alter acomposition of formation fluids produced from the formation.

In some embodiments, a power (Pwr) required to generate a heating rate(h) in a selected volume (V) of a hydrocarbon containing formation maybe determined by the following equation: Pwr=h*V*C_(V)*ρ_(B). In thisequation, an average heat capacity of the hydrocarbon containingformation may be described as C_(V). The average heat capacity of thehydrocarbon containing formation may be a relatively constant value.Average heat capacity may be estimated or determined using one or moresamples taken from a hydrocarbon containing formation, or measured insitu using a thermal pulse test. Methods of determining average heatcapacity based on a thermal pulse test are described by I. Berchenko, E.Detournay. N. Chandler, J. Martino, and E. Kozak, “In-situ measurementof some thermoporoelastic parameters of a granite” in Poromechanics, ATribute to Maurice A. Biot, pages 545-550, Rotterdam, 1998 (Balkema),which is incorporated by reference as if fully set forth herein.

In addition, an average bulk density of the hydrocarbon containingformation may be described as ρ_(B). The average bulk density of thehydrocarbon containing formation may be a relatively constant value.Average bulk density may be estimated or determined using one or moresamples taken from a hydrocarbon containing formation. In certainembodiments the product of average heat capacity and average bulkdensity of the hydrocarbon containing formation may be a relativelyconstant value (such product can be assessed in situ using a thermalpulse test). A determined power may be used to determine heat providedfrom a heat source into the selected volume such that the selectedvolume may be heated at a heating rate, h. For example, a heating ratemay be less than about 3° C./day, and even less than about 2° C./day. Inthis manner, a heating rate within a range of heating rates may bemaintained within the selected volume. It is to be understood that inthis context “power” is used to describe energy input per time. The formof such energy input may, however, vary as described herein (i.e.,energy may be provided from electrical resistance heaters, combustionheaters. etc.).

The heating rate may be selected based on a number of factors including,but not limited to, the maximum temperature possible at the well, apredetermined quality of formation fluids that may be produced from theformation, etc. A quality of hydrocarbon fluids may be defined by an APIgravity of condensable hydrocarbons, by olefin content, by the nitrogen,sulfur and/or oxygen content, etc. In an embodiment, heat may beprovided to at least a portion of a hydrocarbon containing formation toproduce formation fluids having an API gravity of greater than about20°. The API gravity may vary, however, depending on, for example, theheating rate and a pressure within the portion of the formation.

In some embodiments, subsurface pressure in a hydrocarbon containingformation may correspond to the fluid pressure generated within theformation. Heating hydrocarbons within a hydrocarbon containingformation may generate fluids, for example, by pyrolysis. The generatedfluids may be vaporized within the formation. Fluids that contribute tothe increase in pressure may include, but are not limited to, fluidsproduced during pyrolysis and water vaporized during heating. Theproduced pyrolysis fluids may include, but are not limited to,hydrocarbons, water, oxides of carbon, ammonia, molecular nitrogen, andmolecular hydrogen. Therefore, as temperatures within a selected sectionof a heated portion of the formation increase, a pressure within theselected section may increase as a result of increased fluid generationand vaporization of water.

In some embodiments, pressure within a selected section of a heatedportion of a hydrocarbon containing formation may vary depending on, forexample, depth, distance from a heat source, a richness of thehydrocarbons within the hydrocarbon containing formation, and/or adistance from a producer well. Pressure within a formation may bedetermined at a number of different locations, which may include but maynot be limited to, at a wellhead and at varying depths within awellbore. In some embodiments, pressure may be measured at a producerwell. In alternate embodiments, pressure may be measured at a heaterwell.

Heating of a hydrocarbon containing formation to a pyrolysis temperaturerange may occur before substantial permeability has been generatedwithin the hydrocarbon containing formation. An initial lack ofpermeability may prevent the transport of generated fluids from apyrolysis zone within the formation. In this manner, as heat isinitially transferred from a heat source to a hydrocarbon containingformation, a fluid pressure within the hydrocarbon containing formationmay increase proximate to a heat source. Such an increase in fluidpressure may be caused by, for example, generation of fluids duringpyrolysis of at least some hydrocarbons in the formation. The increasedfluid pressure may be released, monitored, altered, and/or controlledthrough such a heat source. For example, the heat source may include avalve as described in above embodiments. Such a valve may be configuredto control a flow rate of fluids out of and into the heat source. Inaddition, the heat source may include an open hole configuration throughwhich pressure may be released.

Alternatively, pressure generated by expansion of pyrolysis fluids orother fluids generated in the formation may be allowed to increasealthough an open path to the production well or any other pressure sinkmay not yet exist in the formation. In addition, a fluid pressure may beallowed to increase to a lithostatic pressure. Fractures in thehydrocarbon containing formation may form when the fluid pressure equalsor exceeds the lithostatic pressure. For example, fractures may formfrom a heat source to a production well. The generation of fractureswithin the heated portion may reduce pressure within the portion due tothe production of formation fluids through a production well. Tomaintain a selected pressure within the heated portion, a back pressuremay be maintained at the production well.

Fluid pressure within a hydrocarbon containing formation may varydepending upon, for example, thermal expansion of hydrocarbons,generation of pyrolysis fluids, and withdrawal of generated fluids fromthe formation. For example, as fluids are generated within the formationa fluid pressure within the pores may increase. Removal of generatedfluids from the formation may decrease a fluid pressure within theformation.

In an embodiment, a pressure may be increased within a selected sectionof a portion of a hydrocarbon containing formation to a selectedpressure during pyrolysis. A selected pressure may be within a rangefrom about 2 bars absolute to about 72 bars absolute or, in someembodiments, 2 bars absolute to 36 bars absolute. Alternatively, aselected pressure may be within a range from about 2 bars absolute toabout 18 bars absolute. For example, in certain embodiments, a majorityof hydrocarbon fluids may be produced from a formation having a pressurewithin a range from about 2 bars absolute to about 18 bars absolute. Thepressure during pyrolysis may vary or be varied. The pressure may bevaried to alter and/or control a composition of a formation fluidproduced, to control a percentage of condensable fluid as compared tonon-condensable fluid, and/or to control an API gravity of fluid beingproduced. For example, decreasing pressure may result in production of alarger condensable fluid component, and the fluid may contain a largerpercentage of olefins, and vice versa.

In certain embodiments, pressure within a portion of a hydrocarboncontaining formation will increase due to fluid generation within theheated portion. In addition, such increased pressure may be maintainedwithin the heated portion of the formation. For example, increasedpressure within the formation may be maintained by bleeding off agenerated formation fluid through heat sources and/or by controlling theamount of formation fluid produced from the formation through productionwells. Maintaining increased pressure within a formation inhibitsformation subsidence. In addition, maintaining increased pressure withina formation tends to reduce the required sizes of collection conduitsthat are used to transport condensable hydrocarbons. Furthermore,maintaining increased pressure within the heated portion may reduceand/or substantially eliminate the need to compress formation fluids atthe surface because the formation products will usually be produced athigher pressure. Maintaining increased pressure within a formation mayalso facilitate generation of electricity from produced non-condensablefluid. For example, the produced non-condensable fluid may be passedthrough a turbine to generate electricity.

Increased pressure in the formation may also be maintained to producemore and/or improved formation fluids. In certain embodiments,significant amounts (e.g., a majority) of the formation fluids producedfrom a formation within the pyrolysis pressure range may includenon-condensable hydrocarbons. Pressure may be selectively increasedand/or maintained within the formation, and formation fluids can beproduced at or near such increased and/or maintained pressures. Aspressure within a formation is increased, formation fluids produced fromthe formation will, in many instances, include a larger portion ofnon-condensable hydrocarbons. In this manner, a significant amount(e.g., a majority) of the formation fluids produced at such a pressuremay include a lighter and higher quality condensable hydrocarbons thanformation fluids produced at a lower pressure.

In addition, a pressure may be maintained within a heated portion of ahydrocarbon containing formation to substantially inhibit production offormation fluids having carbon numbers greater than, for example, about25. For example, increasing a pressure within the portion of thehydrocarbon containing formation may increase a boiling point of a fluidwithin the portion. Such an increase in the boiling point of a fluid maysubstantially inhibit production of formation fluids having relativelyhigh carbon numbers, and/or production of multi-ring hydrocarboncompounds, because such formation fluids tend to remain in the formationas liquids until they crack.

In addition, increasing a pressure within a portion of a hydrocarboncontaining formation may result in an increase in API gravity offormation fluids produced from the formation. Higher pressures mayincrease production of shorter chain hydrocarbon fluids, which may havehigher API gravity values.

In an embodiment, a pressure within a heated portion of the formationmay surprisingly increase the quality of relatively high qualitypyrolyzation fluids, the quantity of relatively high qualitypyrolyzation fluids, and/or vapor phase transport of the pyrolyzationfluids within the formation. Increasing the pressure often permitsproduction of lower molecular weight hydrocarbons since such lowermolecular weight hydrocarbons will more readily transport in the vaporphase in the formation. Generation of lower molecular weighthydrocarbons (and corresponding increased vapor phase transport) isbelieved to be due, in part, to autogenous generation and reaction ofhydrogen within a portion of the hydrocarbon containing formation. Forexample, maintaining an increased pressure may force hydrogen generatedin the heated portion into a liquid phase (e.g. by dissolving). Inaddition, heating the portion to a temperature within a pyrolysistemperature range may pyrolyze at least some of the hydrocarbons withinthe formation to generate pyrolyzation fluids in the liquid phase. Thegenerated components may include a double bond and/or a radical. H₂ inthe liquid phase may reduce the double bond of the generatedpyrolyzation fluids, thereby reducing a potential for polymerization ofthe generated pyrolyzation fluids. In addition, hydrogen may alsoneutralize radicals in the generated pyrolyzation fluids. Therefore, H₂in the liquid phase may substantially inhibit the generated pyrolyzationfluids from reacting with each other and/or with other compounds in theformation. In this manner, shorter chain hydrocarbons may enter thevapor phase and may be produced from the formation.

Increasing the formation pressure to increase the amount of pyrolyzationfluids in the vapor phase may significantly reduce the potential forcoking within the selected section of the formation. A coking reactionmay occur in the liquid phase. Since many of the generated componentsmay be transformed into short chain hydrocarbons and may enter the vaporphase, coking within the selected section may decrease.

Increasing the formation pressure to increase the amount of pyrolyzationfluids in the vapor phase is also beneficial because doing so permitsincreased recovery of lighter (and relatively high quality) pyrolyzationfluids. In general, pyrolyzation fluids are more quickly produced, withless residuals, when such fluids are in the vapor phase rather than inthe liquid phase. Undesirable polymerization reactions also tend tooccur more frequently when the pyrolyzation fluids are in the liquidphase instead of the vapor phase. In addition, when pyrolyzation fluidsare produced in the vapor phase, fewer production wells/area are needed,thereby reducing project costs.

In an embodiment, a portion of a hydrocarbon containing formation may beheated to increase a partial pressure of H₂. In some embodiments, anincreased H₂ partial pressure may include H₂ partial pressures in arange from about 1 bar absolute to about 7 bars absolute. Alternatively,an increased H₂ partial pressure range may include H₂ partial pressuresin a range from about 5 bars absolute to about 7 bars absolute. Forexample, a majority of hydrocarbon fluids may be produced within a rangeof about 5 bars absolute to about 7 bars absolute. A range of H₂ partialpressures within the pyrolysis H₂ partial pressure range may vary,however. depending on, for example, a temperature and a pressure of theheated portion of the formation.

Maintaining a H₂ partial pressure within the formation of greater thanatmospheric pressure may increase an API value of produced condensablehydrocarbon fluids. For example, maintaining such a H₂ partial pressuremay increase an API value of produced condensable hydrocarbon fluids togreater than about 25 or, in some instances, greater than about 30.Maintaining such a H₂ partial pressure within a heated portion of ahydrocarbon containing formation may increase a concentration of H₂within the heated portion such that H₂ may be available to react withpyrolyzed components of the hydrocarbons. Reaction of H₂ with thepyrolyzed components of hydrocarbons may reduce polymerization ofolefins into tars and other cross-linked, difficult to upgrade,products. Such products may have lower API gravity values. Therefore,production of hydrocarbon fluids having low API gravity values may besubstantially inhibited.

A valve may be configured to maintain, alter, and/or control a pressurewithin a heated portion of a hydrocarbon containing formation. Forexample, a heat source disposed within a hydrocarbon containingformation may be coupled to a valve. The valve may be configured torelease fluid from the formation through the heater source. In addition,a pressure valve may be coupled to a production well, which may bedisposed within the hydrocarbon containing formation. In someembodiments, fluids released by the valves may be collected andtransported to a surface unit for further processing and/or treatment.

An in situ conversion process for hydrocarbons may include providingheat to a portion of a hydrocarbon containing formation, and controllinga temperature, rate of temperature increase, and/or a pressure withinthe heated portion. For example, a pressure within the heated portionmay be controlled using pressure valves disposed within a heater well ora production well as described herein. A temperature and/or a rate oftemperature increase of the heated portion may be controlled, forexample, by altering an amount of energy supplied to one or more heatsources.

Controlling a pressure and a temperature within a hydrocarbon containingformation will, in most instances, affect properties of the producedformation fluids. For example, a composition or a quality of formationfluids produced from the formation may be altered by altering an averagepressure and/or an average temperature in the selected section of theheated portion. The quality of the produced fluids may be defined by aproperty which may include, but may not be limited to, API gravity,percent olefins in the produced formation fluids, ethene to ethaneratio, atomic hydrogen to carbon ratio, percent of hydrocarbons withinproduced formation fluids having carbon numbers greater than 25, totalequivalent production (gas and liquid), total liquids production, and/orliquid yield as a percent of Fischer Assay. For example, controlling thequality of the produced formation fluids may include controlling averagepressure and average temperature in the selected section such that theaverage assessed pressure in the selected section may be greater thanthe pressure (p) as set forth in the form of the following relationshipfor an assessed average temperature (T) in the selected section:$p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}$

where p is measured in psia (pounds per square inch absolute), T ismeasured in degrees Kelvin, A and B are parameters dependent on thevalue of the selected property. An assessed average temperature may bedetermined as described herein.

The relationship given above may be rewritten such that the natural logof pressure may be a linear function of an inverse of temperature. Thisform of the relationship may be rewritten: ln(p)=A/T+B. In a plot of theabsolute pressure as a function of the reciprocal of the absolutetemperature, A is the slope and B is the intercept. The intercept B isdefined to be the natural logarithm of the pressure as the reciprocal ofthe temperature approaches zero. Therefore, the slope and interceptvalues (A and B) of the pressure-temperature relationship may bedetermined from two pressure-temperature data points for a given valueof a selected property. The pressure-temperature data points may includean average pressure within a formation and an average temperature withinthe formation at which the particular value of the property was, or maybe, produced from the formation. For example, the pressure-temperaturedata points may be obtained from an experiment such as a laboratoryexperiment or a field experiment.

A relationship between the slope parameter, A, and a value of a propertyof formation fluids may be determined. For example, values of A may beplotted as a function of values of a formation fluid property. A cubicpolynomial may be fitted to these data. For example, a cubic polynomialrelationship such as A=a₁*(property)³+a₂*(property)²+a₃*(property)+a₄may be fitted to the data, where a₁, a₂, a₃, and a₄ are empiricalconstants that may describe a relationship between the first parameter,A, and a property of a formation fluid. Alternatively, relationshipshaving other functional forms such as another order polynomial or alogarithmic function may be fitted to the data. In this manner, a₁, a₂,. . . , may be estimated from the results of the data fitting.Similarly, a relationship between the second parameter, B, and a valueof a property of formation fluids may be determined. For example, valuesof B may be plotted as a function of values of a property of a formationfluid. A cubic polynomial may also be fitted to the data. For example, acubic polynomial relationship such asB=b₁*(property)³+b₂*(property)²+b₃*(property)+b₄ may be fitted to thedata, where b₁, b₂, b₃, and b₄ are empirical constants that may describea relationship between the parameter B, and the value of a property of aformation fluid. As such, b₁, b₂, b₃, and b₄ may be estimated fromresults of fitting the data. For example, TABLES 1a and 1b listestimated empirical constants determined for several properties of aformation fluid for Green River oil shale as described above.

TABLE 1a PROPERTY a₁ a₂ a₃ a₄ API Gravity −0.738549 −8.893902 4752.182−145484.6 Ethene/Ethane Ratio −15543409 3261335 −303588.8 −2767.469Weight Percent of Hydrocarbons 0.1621956 −8.85952 547.9571 −24684.9Having a Carbon Number Greater Than 25 Atomic H/C Ratio 2950062−16982456 32584767 −20846821 Liquid Production (gal/ton) 119.2978−5972.91 96989 −524689 Equivalent Liquid Production −6.24976 212.9383−777.217 −39353.47 (gal/ton) % Fischer Assay 0.5026013 −126.592 9813.139−252736

TABLE 1b PROPERTY b₁ b₂ b₃ b₄ API Gravity 0.003843 −0.279424 3.39107196.67251 Ethene/Ethane Ratio −8974.317 2593.058 −40.78874 23.31395Weight Percent of Hydrocarbons −0.0005022 0.026258 −1.12695 44.49521Having a Carbon Number Greater Than 25 Atomic H/C Ratio 790.0532−4199.454 7328.572 −4156.599 Liquid Production (gal/ton) −0.178088.914098 −144.999 793.2477 Equivalent Liquid Production −0.033872.778804 −72.6457 650.7211 (gal/ton) % Fischer Assay −0.0007901 0.196296−15.1369 395.3574

To determine an average pressure and an average temperature that may beused to produce a formation fluid having a selected property, the valueof the selected property and the empirical constants as described abovemay be used to determine values for the first parameter A, and thesecond parameter B, according to the following relationships:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄

For example, TABLES 2a-2g list estimated values for the parameter A, andapproximate values for the parameter B, as determined for a selectedproperty of a formation fluid as described above.

TABLE 2a API Gravity A B 20 degrees −59906.9 83.46594 25 degrees−43778.5 66.85148 30 degrees −30864.5 50.67593 35 degrees −21718.537.82131 40 degrees −16894.7 31.16965 45 degrees −16946.8 33.60297

TABLE 2b Ethene/Ethane Ratio A B 0.20 −57379 83.145 0.10 −16056 27.6520.05 −11736 21.986 0.01 −5492.8 14.234

TABLE 2c Weight Percent of Hydrocarbons Having a Carbon Number GreaterThan 25 A B 25% −14206 25.123 20% −15972 28.442 15% −17912 31.804 10%−19929 35.349  5% −21956 38.849  1% −24146 43.394

TABLE 2d Atomic H/C Ratio A B 1.7 −38360 60.531 1.8 −12635 23.989 1.9−7953.1 17.889 2.0 −6613.1 16.364

TABLE 2e Liquid Production (gal/ton) A B 14 gal/ton −10179 21.780 16gal/ton −13285 25.866 18 gal/ton −18364 32.882 20 gal/ton −19689 34.282

TABLE 2f Equivalent Liquid Production (gal/ton) A B 20 gal/ton −1972138.338 25 gal/ton −23350 42.052 30 gal/ton −39768.9 57.68

TABLE 2g % Fischer Assay A B 60% −11118 23.156 70% −13726 26.635 80%−20543 36.191 90% −28554 47.084

The determined values for the parameter A, and the parameter B, may beused to determine an average pressure in the selected section of theformation using an assessed average temperature, T, in the selectedsection. The assessed average temperature may be determined as describedherein. For example, an average pressure of the selected section may bedetermined by the relationship: p=exp[(A/T)+B], in which p is measuredin psia, and T is measured in degrees Kelvin. Alternatively, an averageabsolute pressure of the selected section, measured in bars, may bedetermined using the following relationship:p_(bars)=exp[(A/T)+B−2.6744]. In this manner, an average pressure withinthe selected section may be controlled such that an average pressurewithin the selected section is adjusted to the average pressure asdetermined above, in order to produce a formation fluid from theselected section having a selected property.

Alternatively, the determined values for the parameter A, and theparameter B, may be used to determine an average temperature in theselected section of the formation using an assessed average pressure, p,in the selected section. The assessed average pressure may be determinedas described herein. Therefore, using the relationship described above,an average temperature within the selected section may be controlled toapproximate the calculated average temperature in order to producehydrocarbon fluids having a selected property.

As described herein, a composition of formation fluids produced from aformation may be varied by altering at least one operating condition ofan in situ conversion process for hydrocarbons. In addition, at leastone operating condition may be determined by using acomputer-implemented method. For example, an operating condition mayinclude, but is not limited to, a pressure in the formation, atemperature in the formation, a heating rate of the formation, a powersupplied to a heat source, and/or a flow rate of a synthesis gasgenerating fluid. The computer-implemented method may include measuringat least one property of the formation. For example, measured propertiesmay include a thickness of a layer containing hydrocarbons, vitrinitereflectance, hydrogen content, oxygen content, moisture content,depth/width of the hydrocarbon containing formation, and otherproperties otherwise described herein.

At least one measured property may be inputted into a computerexecutable program. The program may be operable to determine at leastone operating condition from a measured property. In addition, at leastone property of selected formation fluids may be input into the program.For example, properties of selected formation fluids may include, butare not limited to, API gravity, olefin content, carbon numberdistribution, ethene to ethane ratio, and atomic carbon to hydrogenratio. The program may also be operable to determine at least oneoperating condition from a property of the selected formation fluids. Inthis manner, an operating condition of an in situ conversion process maybe altered to be approximate at least one determined operating conditionsuch that production of selected formation fluids from the formation mayincrease.

In an embodiment, a computer-implemented method may be used to determineat least one property of a formation fluid that may be produced from ahydrocarbon containing formation for a set of operating conditions as afunction of time. The method may include measuring at least one propertyof the formation and providing at least the one measured property to acomputer program as described herein. In addition, one or more sets ofoperating conditions may also be provided to the computer program. Atleast one of the operating conditions may include, for example, aheating rate or a pressure. One or more sets of operating conditions mayinclude currently used operating conditions (in an in situ conversionprocess) or operating conditions being considered for an in situconversion process. The computer program may be operable to determine atleast one property of a formation fluid that may be produced by an insitu conversion process for hydrocarbons as a function of time using atleast one set of operating conditions and at least one measured propertyof the formation. Furthermore, the method may include comparing adetermined property of the fluid to a selected property. In this manner,if multiple determined properties are generated by the computer program,then the determined property that differs least from a selected propertymay be determined.

Formation fluid properties may vary depending on a location of aproduction well in the formation. For example, a location of aproduction well with respect to a location of a heat source in theformation may affect the composition of formation fluid produced from aformation. In addition, a distance between a production well and a heatsource in a formation may be varied to alter the composition offormation fluid produced from a formation. Decreasing a distance betweena production well and a heat source may increase a temperature at theproduction well. In this manner, a substantial portion of pyrolyzationfluids flowing through a production well may in some instances crack tonon-condensable compounds due to increased temperature at a productionwell. Therefore, a location of a production well with respect to a heatsource may be selected to increase a non-condensable gas fraction of theproduced formation fluids. In addition, a location of a production wellwith respect to a heat source may be selected such that anon-condensable gas fraction of produced formation fluids may be largerthan a condensable gas fraction of the produced formation fluids.

A carbon number distribution of a produced formation fluid may indicatea quality of the produced formation fluid. In general, condensablehydrocarbons with low carbon numbers are considered to be more valuablethan condensable hydrocarbons having higher carbon numbers. Low carbonnumbers may include, for example, carbon numbers less than about 25.High carbon numbers may include carbon numbers greater than about 25. Inan embodiment, an in situ conversion process for hydrocarbons mayinclude providing heat to at least a portion of a formation and allowingheat to transfer such that heat may produce pyrolyzation fluids suchthat a majority of the pyrolyzation fluids have carbon numbers of lessthan approximately 25.

In an embodiment, an in situ conversion process for hydrocarbons mayinclude providing heat to at least a portion of a hydrocarbon containingformation at a rate sufficient to alter and/or control production ofolefins. For example, the process may include heating the portion at arate to produce formation fluids having an olefin content of less thanabout 10% by weight of condensable hydrocarbons of the formation fluids.Reducing olefin production may substantially reduce coating of a pipesurface by such olefins, thereby reducing difficulty associated withtransporting hydrocarbons through such piping. Reducing olefinproduction may also tend to inhibit polymerization of hydrocarbonsduring pyrolysis, thereby increasing permeability in the formationand/or enhancing the quality of produced fluids (e.g., by lowering thecarbon number distribution, increasing API gravity, etc.).

In some embodiments, however, the portion may be heated at a rate toselectively increase the olefin content of condensable hydrocarbons inthe produced fluids. For example, olefins may be separated from suchcondensable hydrocarbons and may be used to produce additional products.

In some embodiments, the portion may be heated at a rate to selectivelyincrease the content of phenol and substituted phenols of condensablehydrocarbons in the produced fluids. For example, phenol and/orsubstituted phenols may be separated from such condensable hydrocarbonsand may be used to produce additional products. The resource may, insome embodiments, be selected to enhance production of phenol and/orsubstituted phenols.

Hydrocarbons in the produced fluids may include a mixture of a number ofdifferent components, some of which are condensable and some of whichare not. The fraction of non-condensable hydrocarbons within theproduced fluid may be altered and/or controlled by altering,controlling, and/or maintaining a temperature within a pyrolysistemperature range in a heated portion of the hydrocarbon containingformation. Additionally, the fraction of non-condensable hydrocarbonswithin the produced fluids may be altered and/or controlled by altering,controlling, and/or maintaining a pressure within the heated portion. Insome embodiments, surface facilities may be configured to separatecondensable and non-condensable hydrocarbons of a produced fluid.

In some embodiments, the non-condensable hydrocarbons may include, butare not limited to, hydrocarbons having less than about 5 carbon atoms,H₂, CO₂, ammonia, H₂S, N₂ and/or CO. In certain embodiments,non-condensable hydrocarbons of a fluid produced from a portion of ahydrocarbon containing formation may have a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4 (“C₂₋₄” hydrocarbons) to methaneof greater than about 0.3, greater than about 0.75, or greater thanabout 1 in some circumstances. For example, non-condensable hydrocarbonsof a fluid produced from a portion of an oil shale or heavy hydrocarboncontaining formation may have a weight ratio of hydrocarbons havingcarbon numbers from 2 through 4, to methane, of greater thanapproximately 1. In addition, non-condensable hydrocarbons of a fluidproduced from a portion of a coal formation may have a weight ratio ofhydrocarbons having carbon numbers from 2 through 4, to methane, ofgreater than approximately 0.3.

Such weight ratios of C₂₋₄ hydrocarbons to methane are believed to bebeneficial as compared to similar weight ratios produced from otherformations. Such weight ratios indicate higher amounts of hydrocarbonswith 2, 3, and/or 4 carbons (e.g., ethane, propane, and butane) than isnormally present in gases produced from formations. Such hydrocarbonsare often more valuable. Production of hydrocarbons with such weightratios is believed to be due to the conditions applied to the formationduring pyrolysis (e.g., controlled heating and/or pressure used inreducing environments, or at least non-oxidizing environments). It isbelieved that in such conditions longer chain hydrocarbons can be moreeasily broken down to form substantially smaller (and in many cases moresaturated) compounds such as C₂₋₄ hydrocarbons. The C₂₋₄ hydrocarbons tomethane weight ratio may vary depending on, for example, a temperatureof the heated portion and a heating rate of the heated portion.

In certain embodiments, the API gravity of the hydrocarbons in a fluidproduced from a hydrocarbon containing formation may be approximately 25or above (e.g., 30, 40, 50, etc.).

Methane and at least a portion of ethane may be separated fromnon-condensable hydrocarbons in the produced fluid and may be utilizedas natural gas. A portion of propane and butane may be separated fromnon-condensable hydrocarbons of the produced fluid. In addition, theseparated propane and butane may be utilized as fuels or as feedstocksfor producing other hydrocarbons. A portion of the produced fluid havingcarbon numbers less than 4 may be reformed, as described herein, in theformation to produce additional H₂ and/or methane. In addition, ethane,propane, and butane may be separated from the non-condensablehydrocarbons and may be used to generate olefins.

The non-condensable hydrocarbons of fluid produced from a hydrocarboncontaining formation may have a H₂ content of greater than about 5% byweight, greater than about 10% by weight, or even greater than about 15%by weight. The H₂ may be used, for example, as a fuel for a fuel cell,to hydrogenate hydrocarbon fluids in situ, and/or to hydrogenatehydrocarbon fluids ex situ. In addition, presence of H₂ within aformation fluid in a heated section of a hydrocarbon containingformation is believed to increase the quality of produced fluids. Incertain embodiments, the hydrogen to carbon atomic ratio of a producedfluid may be at least approximately 1.7 or above. For example, thehydrogen to carbon atomic ratio of a produced fluid may be approximately1.8, approximately 1.9, or greater.

The non-condensable hydrocarbons may include some hydrogen sulfide. Thenon-condensable hydrocarbons may be treated to separate the hydrogensulfide from other compounds in the non-condensable hydrocarbons. Theseparated hydrogen sulfide may be used to produce, for example, sulfuricacid, fertilizer, and/or elemental sulfur.

In certain embodiments, fluid produced from a hydrocarbon containingformation by an in situ conversion process may include carbon dioxide.Carbon dioxide produced from the formation may be used, for example, forenhanced oil recovery, as at least a portion of a feedstock forproduction of urea, and/or may be reinjected into a hydrocarboncontaining formation for synthesis gas production and/or coal bedmethane production.

Fluid produced from a hydrocarbon containing formation by an in situconversion process may include carbon monoxide. Carbon monoxide producedfrom the formation may be used, for example, as a feedstock for a fuelcell, as a feedstock for a Fischer Tropsch process, as a feedstock forproduction of methanol, and/or as a feedstock for production of methane.

The condensable hydrocarbons of the produced fluids may be separatedfrom the fluids. In an embodiment, a condensable component may includecondensable hydrocarbons and compounds found in an aqueous phase. Theaqueous phase may be separated from the condensable component. Theammonia content of the total produced fluids may be greater than about0.1% by weight of the fluid, greater than about 0.5% by weight of thefluid, and, in some embodiments, up to about 10% by weight of theproduced fluids. The ammonia may be used to produce, for example, urea.

Certain embodiments of a fluid may be produced in which a majority ofhydrocarbons in the produced fluid have a carbon number of less thanapproximately 25. Alternatively, less than about 15% by weight of thehydrocarbons in the condensable hydrocarbons have a carbon numbergreater than approximately 25. In some embodiments, less than about 5%by weight of hydrocarbons in the condensable hydrocarbons have a carbonnumber greater than approximately 25, and/or less than about 2% byweight of hydrocarbons in the condensable hydrocarbons have a carbonnumber greater than approximately 25.

In certain embodiments, a fluid produced from a formation (e.g., a coalformation) may include oxygenated hydrocarbons. For example, condensablehydrocarbons of the produced fluid may include an amount of oxygenatedhydrocarbons greater than about 5% by weight of the condensablehydrocarbons. Alternatively, the condensable hydrocarbons may include anamount of oxygenated hydrocarbons greater than about 1.0% by weight ofthe condensable hydrocarbons. Furthermore, the condensable hydrocarbonsmay include an amount of oxygenated hydrocarbons greater than about 1.5%by weight of the condensable hydrocarbons or greater than about 2.0% byweight of the condensable hydrocarbons. In an embodiment, the oxygenatedhydrocarbons may include, but are not limited to, phenol and/orsubstituted phenols. In some embodiments, phenol and substituted phenolsmay have more economic value than other products produced from an insitu conversion process. Therefore, an in situ conversion process may beutilized to produce phenol and/or substituted phenols. For example,generation of phenol and/or substituted phenols may increase when afluid pressure within the formation is maintained at a lower pressure.

In some embodiments, condensable hydrocarbons of a fluid produced from ahydrocarbon containing formation may also include olefins. For example,an olefin content of the condensable hydrocarbons may be in a range fromabout 0.1% by weight to about 15% by weight. Alternatively, an olefincontent of the condensable hydrocarbons may also be within a range fromabout 0.1% by weight to about 5% by weight. Furthermore, an olefincontent of the condensable hydrocarbons may also be within a range fromabout 0.1% by weight to about 2.5% by weight. An olefin content of thecondensable hydrocarbons may be altered and/or controlled by controllinga pressure and/or a temperature within the formation. For example,olefin content of the condensable hydrocarbons may be reduced byselectively increasing pressure within the formation, by selectivelydecreasing temperature within the formation, by selectively reducingheating rates within the formation, and/or by selectively increasinghydrogen partial pressures in the formation. In some embodiments, areduced olefin content of the condensable hydrocarbons may be preferred.For example, if a portion of the produced fluids is used to producemotor fuels, a reduced olefin content may be desired.

In alternate embodiments, a higher olefin content may be preferred. Forexample, if a portion of the condensable hydrocarbons may be sold, ahigher olefin content may be preferred due to a high economic value ofolefin products. In some embodiments, olefins may be separated from theproduced fluids and then sold and/or used as a feedstock for theproduction of other compounds.

Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, an olefin content of the non-condensablehydrocarbons may be gauged using an ethene/ethane molar ratio. Incertain embodiments, the ethene/ethane molar ratio may range from about0.001 to about 0.15.

Fluid produced from a hydrocarbon containing formation may includearomatic compounds. For example, the condensable hydrocarbons mayinclude an amount of aromatic compounds greater than about 20% by weightor about 25% by weight of the condensable hydrocarbons. Alternatively,the condensable hydrocarbons may include an amount of aromatic compoundsgreater than about 30% by weight of the condensable hydrocarbons. Thecondensable hydrocarbons may also include relatively low amounts ofcompounds with more than two rings in them (e.g., tri-aromatics orabove). For example, the condensable hydrocarbons may include less thanabout 1% by weight or less than about 2% by weight of tri-aromatics orabove in the condensable hydrocarbons. Alternatively, the condensablehydrocarbons may include less than about 5% by weight of tri-aromaticsor above in the condensable hydrocarbons.

In particular, in certain embodiments, asphaltenes (i.e., largemulti-ring aromatics that may be substantially soluble in hydrocarbons)make up less than about 0.1% by weight of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0% by weight to about 0.1% by weight or, insome embodiments, less than about 0.3% by weight.

Condensable hydrocarbons of a produced fluid may also include relativelylarge amounts of cycloalkanes. For example, the condensable hydrocarbonsmay include a cycloalkane component of from about 5% by weight to about30% by weight of the condensable hydrocarbons.

In certain embodiments, the condensable hydrocarbons of a fluid producedfrom a formation may include compounds containing nitrogen. For example,less than about 1% by weight (when calculated on an elemental basis) ofthe condensable hydrocarbons may be nitrogen (e.g., typically thenitrogen may be in nitrogen containing compounds such as pyridines,amines, amides, carbazoles, etc.).

In certain embodiments, the condensable hydrocarbons of a fluid producedfrom a formation may include compounds containing oxygen. For example,in certain embodiments (e.g., for oil shale and heavy hydrocarbons) lessthan about 1% by weight (when calculated on an elemental basis) of thecondensable hydrocarbons may be oxygen containing compounds (e.g.,typically the oxygen may be in oxygen containing compounds such asphenol, substituted phenols, ketones, etc.). In certain otherembodiments, (e.g., for coal formations) between about 5% by weight andabout 30% by weight of the condensable hydrocarbons may typicallyinclude oxygen containing compounds such as phenols, substitutedphenols, ketones, etc. In some instances, certain compounds containingoxygen (e.g., phenols) may be valuable and, as such, may be economicallyseparated from the produced fluid.

In certain embodiments, condensable hydrocarbons of the fluid producedfrom a formation may include compounds containing sulfur. For example,less than about 1% by weight (when calculated on an elemental basis) ofthe condensable hydrocarbons may be sulfur (e.g., typically the sulfurcontaining compounds may include compounds such as thiophenes,mercaptans, etc.).

Furthermore, the fluid produced from the formation may include ammonia(typically the ammonia may condense with water, if any, produced fromthe formation). For example, the fluid produced from the formation mayin certain embodiments include about 0.05% or more by weight of ammonia.Certain formations (e.g., coal and/or oil shale) may produce largeramounts of ammonia (e.g., up to about 10% by weight of the total fluidproduced may be ammonia).

In addition, a produced fluid from the formation may also includemolecular hydrogen (H₂). For example, the fluid may include a H₂ contentbetween about 10% to about 80% by volume of the non-condensablehydrocarbons.

In some embodiments, at least about 15% by weight of a total organiccarbon content of hydrocarbons in the portion may be transformed intohydrocarbon fluids.

A total potential amount of products that may be produced fromhydrocarbons may be determined by a Fischer Assay. The Fischer Assay isa standard method that involves heating a sample of hydrocarbons toapproximately 500° C. in one hour, collecting products produced from theheated sample, and quantifying the products. In an embodiment, a methodfor treating a hydrocarbon containing formation in situ may includeheating a section of the formation to yield greater than about 60% byweight of the potential amount of products from the hydrocarbons asmeasured by the Fischer Assay.

In certain embodiments, heating of the selected section of the formationmay be controlled to pyrolyze at least about 20% by weight (or in someembodiments about 25% by weight) of the hydrocarbons within the selectedsection of the formation. Conversion of hydrocarbons within a formationmay be limited to inhibit subsidence of the formation.

Heating at least a portion of a formation may cause at least some of thehydrocarbons within the portion to pyrolyze, thereby forming hydrocarbonfragments. The hydrocarbon fragments may be reactive and may react withother compounds in the formation and/or with other hydrocarbon fragmentsproduced by pyrolysis. Reaction of the hydrocarbon fragments with othercompounds and/or with each other, however, may reduce production of aselected product. A reducing agent in or provided to the portion of theformation during heating, however, may increase production of theselected product. An example of a reducing agent may include, but maynot be limited to, H₂. For example, the reducing agent may react withthe hydrocarbon fragments to form a selected product.

In an embodiment, molecular hydrogen may be provided to the formation tocreate a reducing environment. A hydrogenation reaction between themolecular hydrogen and at least some of the hydrocarbons within aportion of the formation may generate heat. The generated heat may beused to heat the portion of the formation. Molecular hydrogen may alsobe generated within the portion of the formation. In this manner, thegenerated H₂ may be used to hydrogenate hydrocarbon fluids within aportion of a formation.

For example, H₂ may be produced from a first portion of the hydrocarboncontaining formation. The H₂ may be produced as a component of a fluidproduced from a first portion. For example, at least a portion of fluidsproduced from a first portion of the formation may be provided to asecond portion of the formation to create a reducing environment withinthe second portion. The second portion of the formation may be heated asdescribed herein. In addition, produced H₂ may be provided to a secondportion of the formation. For example, a partial pressure of H₂ withinthe produced fluid may be greater than a pyrolysis H₂ partial pressure,as measured at a well from which the produced fluid may be produced.

For example, a portion of a hydrocarbon containing formation may beheated in a reducing environment. The presence of a reducing agentduring pyrolysis of at least some of the hydrocarbons in the heatedportion may reduce (e.g., at least partially saturate) at least some ofthe pyrolyzed product. Reducing the pyrolyzed product may decrease aconcentration of olefins in hydrocarbon fluids. Reducing the pyrolysisproducts may improve the product quality of the hydrocarbon fluids.

An embodiment of a method for treating a hydrocarbon containingformation in situ may include generating H₂ and hydrocarbon fluidswithin the formation. In addition, the method may include hydrogenatingthe generated hydrocarbon fluids using the H₂ within the formation. Insome embodiments, the method may also include providing the generated H₂to a portion of the formation.

In an embodiment, a method of treating a portion of a hydrocarboncontaining formation may include heating the portion such that a thermalconductivity of a selected section of the heated portion increases. Forexample, porosity and permeability within a selected section of theportion may increase substantially during heating such that heat may betransferred through the formation not only by conduction but also byconvection and/or by radiation from a heat source. In this manner, suchradiant and convective transfer of heat may increase an apparent thermalconductivity of the selected section and, consequently, the thermaldiffusivity. The large apparent thermal diffusivity may make heating atleast a portion of a hydrocarbon containing formation from heat sourcesfeasible. For example, a combination of conductive, radiant, and/orconvective heating may accelerate heating. Such accelerated heating maysignificantly decrease a time required for producing hydrocarbons andmay significantly increase the economic feasibility of commercializationof an in situ conversion process. In a further embodiment, the in situconversion process for a hydrocarbon containing formation may alsoinclude providing heat to the heated portion to increase a thermalconductivity of a selected section to greater than about 0.5 W/(m ° C.)or about 0.6 W/(m ° C.).

In some embodiments, an in situ conversion process for a coal formationmay increase the rank level of coal within a heated portion of the coal.The increase in rank level, as assessed by the vitrinite reflectance, ofthe coal may coincide with a substantial change of the structure (e.g.,molecular changes in the carbon structure) of the coal. The changedstructure of the coal may have a higher thermal conductivity.

Thermal diffusivity within a hydrocarbon containing formation may varydepending on, for example, a density of the hydrocarbon containingformation, a heat capacity of the formation, and a thermal conductivityof the formation. As pyrolysis occurs within a selected section, thehydrocarbon containing mass may be removed from the selected section.The removal of mass may include, but is not limited to, removal of waterand a transformation of hydrocarbons to formation fluids. For example, alower thermal conductivity may be expected as water is removed from acoal formation. This effect may vary significantly at different depths.At greater depths a lithostatic pressure may be higher, and may closecertain openings (e.g., cleats and/or fractures) in the coal. Theclosure of the coal openings may increase a thermal conductivity of thecoal. In some embodiments, a higher thermal conductivity may be observeddue to a higher lithostatic pressure.

In some embodiments, an in situ conversion process may generatemolecular hydrogen during the pyrolysis process. In addition, pyrolysistends to increase the porosity/void spaces in the formation. Void spacesin the formation may contain hydrogen gas generated by the pyrolysisprocess. Hydrogen gas may have about six times the thermal conductivityof nitrogen or air. This may raise the thermal conductivity of theformation.

Certain embodiments described herein will in many instances be able toeconomically treat formations that were previously believed to beuneconomical. Such treatment will be possible because of the surprisingincreases in thermal conductivity and thermal diffusivity that can beachieved with such embodiments. These surprising results are illustratedby the fact that prior literature indicated that certain hydrocarboncontaining formations, such as coal, exhibited relatively low values forthermal conductivity and thermal diffusivity when heated. For example,in government report No. 8364 by J. M. Singer and R. P. Tye entitled“Thermal, Mechanical, and Physical Properties of Selected BituminousCoals and Cokes,” U.S. Department of the Interior, Bureau of Mines(1979), the authors report the thermal conductivity and thermaldiffusivity for four bituminous coals. This government report includesgraphs of thermal conductivity and diffusivity that show relatively lowvalues up to about 400° C. (e.g., thermal conductivity is about 0.2 W/(m° C.) or below, and thermal diffusivity is below about 1.7×10⁻³ cm²/s).This government report states that “coals and cokes are excellentthermal insulators.”

In contrast, in certain embodiments described herein hydrocarboncontaining resources (e.g., coal) may be treated such that the thermalconductivity and thermal diffusivity are significantly higher (e.g.,thermal conductivity at or above about 0.5 W/(m ° C.) and thermaldiffusivity at or above 4.1×10⁻³ cm²/s) than would be expected based onprevious literature such as government report No. 8364. If treated asdescribed in certain embodiments herein, coal does not act as “anexcellent thermal insulator.” Instead, heat can and does transfer and/ordiffuse into the formation at significantly higher (and better) ratesthan would be expected according to the literature, therebysignificantly enhancing economic viability of treating the formation.

In an embodiment, heating a portion of a hydrocarbon containingformation in situ to a temperature less than an upper pyrolysistemperature may increase permeability of the heated portion. Forexample, permeability may increase due to formation of fractures withinthe heated portion caused by application of heat. As a temperature ofthe heated portion increases, water may be removed due to vaporization.The vaporized water may escape and/or be removed from the formation.Removal of water may also increase the permeability of the heatedportion. In addition, permeability of the heated portion may alsoincrease as a result of production of hydrocarbons from pyrolysis of atleast some of the hydrocarbons within the heated portion on amacroscopic scale. In an embodiment, a permeability of a selectedsection within a heated portion of a hydrocarbon containing formationmay be substantially uniform. For example, heating by conduction may besubstantially uniform, and thus a permeability created by conductiveheating may also be substantially uniform. In the context of this patent“substantially uniform permeability” means that the assessed (e.g.,calculated or estimated) permeability of any selected portion in theformation does not vary by more than a factor of 10 from the assessedaverage permeability of such selected portion.

Permeability of a selected section within the heated portion of thehydrocarbon containing formation may also rapidly increase while theselected section is heated by conduction. For example, permeability ofan impermeable hydrocarbon containing formation may be less than about0.1 millidarcy (9.9×10⁻¹⁷ m²) before treatment. In some embodiments,pyrolyzing at least a portion of a hydrocarbon containing formation mayincrease a permeability within a selected section of the portion togreater than about 10 millidarcy, 100 millidarcy, 1 Darcy, 10 Darcy, 20Darcy, or 50 Darcy. Therefore, a permeability of a selected section ofthe portion may increase by a factor of more than about 1,000, 10,000,or 100,000.

In some embodiments, superposition (e.g., overlapping) of heat from oneor more heat sources may result in substantially uniform heating of aportion of a hydrocarbon containing formation. Since formations duringheating will typically have temperature profiles throughout them, in thecontext of this patent “substantially uniform” heating means heatingsuch that the temperatures in a majority of the section do not vary bymore than 100° C. from the assessed average temperature in the majorityof the selected section (volume) being treated.

Substantially uniform heating of the hydrocarbon containing formationmay result in a substantially uniform increase in permeability. Forexample, uniformly heating may generate a series of substantiallyuniform fractures within the heated portion due to thermal stressesgenerated in the formation. Heating substantially uniformly may generatepyrolysis fluids from the portion in a substantially homogeneous manner.Water removed due to vaporization and production may result in increasedpermeability of the heated portion. In addition to creating fracturesdue to thermal stresses, fractures may also be generated due to fluidpressure increase. As fluids are generated within the heated portion, afluid pressure within the heated portion may also increase. As the fluidpressure approaches a lithostatic pressure of the heated portion,fractures may be generated. Substantially uniform heating andhomogeneous generation of fluids may generate substantially uniformfractures within the heated portion. In some embodiments, a permeabilityof a heated section of a hydrocarbon containing formation may not varyby more than a factor of about 10.

Removal of hydrocarbons due to treating at least a portion of ahydrocarbon containing formation, as described in any of the aboveembodiments, may also occur on a microscopic scale. Hydrocarbons may beremoved from micropores within the portion due to heating. Microporesmay be generally defined as pores having a cross-sectional dimension ofless than about 1000 Å. In this manner, removal of solid hydrocarbonsmay result in a substantially uniform increase in porosity within atleast a selected section of the heated portion. Heating the portion of ahydrocarbon containing formation, as described in any of the aboveembodiments, may substantially uniformly increase a porosity of aselected section within the heated portion. In the context of thispatent “substantially uniform porosity” means that the assessed (e.g.,calculated or estimated) porosity of any selected portion in theformation does not vary by more than about 25% from the assessed averageporosity of such selected portion.

Physical characteristics of a portion of a hydrocarbon containingformation after pyrolysis may be similar to those of a porous bed. Forexample, a portion of a hydrocarbon containing formation after pyrolysismay include particles having sizes of about several millimeters. Suchphysical characteristics may differ from physical characteristics of ahydrocarbon containing formation that may be subjected to injection ofgases that bum hydrocarbons in order to heat the hydrocarbons. Suchgases injected into virgin or fractured formations may tend to channeland may not be uniformly distributed throughout the formation. Incontrast, a gas injected into a pyrolyzed portion of a hydrocarboncontaining formation may readily and substantially uniformly contact thecarbon and/or hydrocarbons remaining in the formation. In addition,gases produced by heating the hydrocarbons may be transferred asignificant distance within the heated portion of the formation with aminimal pressure loss. Such transfer of gases may be particularlyadvantageous, for example, in treating a steeply dipping hydrocarboncontaining formation.

Synthesis gas may be produced from a portion of a hydrocarbon containingformation containing, e.g., coal, oil shale, other kerogen containingformations, heavy hydrocarbons (tar sands, etc.) and other bitumencontaining formations. The hydrocarbon containing formation may beheated prior to synthesis gas generation to produce a substantiallyuniform, relatively high permeability formation. In an embodiment,synthesis gas production may be commenced after production of pyrolysisfluids has been substantially exhausted or becomes uneconomical.Alternately, synthesis gas generation may be commenced beforesubstantial exhaustion or uneconomical pyrolysis fluid production hasbeen achieved if production of synthesis gas will be more economicallyfavorable. Formation temperatures will usually be higher than pyrolysistemperatures during synthesis gas generation. Raising the formationtemperature from pyrolysis temperatures to synthesis gas generationtemperatures allows further utilization of heat applied to the formationto pyrolyze the formation. While raising a temperature of a formationfrom pyrolysis temperatures to synthesis gas temperatures, methaneand/or H₂ may be produced from the formation.

Producing synthesis gas from a formation from which pyrolyzation fluidshave been previously removed allows a synthesis gas to be produced thatincludes mostly H₂, CO, water and/or CO₂. Produced synthesis gas, incertain embodiments, may have substantially no hydrocarbon componentunless a separate source hydrocarbon stream is introduced into theformation with or in addition to the synthesis gas producing fluid.Producing synthesis gas from a substantially uniform, relatively highpermeability formation that was formed by slowly heating a formationthrough pyrolysis temperatures may allow for easy introduction of asynthesis gas generating fluid into the formation, and may allow thesynthesis gas generating fluid to contact a relatively large portion ofthe formation. The synthesis gas generating fluid can do so because thepermeability of the formation has been increased during pyrolysis and/orbecause the surface area per volume in the formation has increasedduring pyrolysis. The relatively large surface area (e.g., “contactarea”) in the post-pyrolysis formation tends to allow synthesis gasgenerating reactions to be substantially at equilibrium conditions forC, H₂, CO, water and CO₂. Reactions in which methane is formed may,however, not be at equilibrium because they are kinetically limited. Therelatively high, substantially uniform formation permeability may allowproduction wells to be spaced farther apart than production wells usedduring pyrolysis of the formation.

A temperature of at least a portion of a formation that is used togenerate synthesis gas may be raised to a synthesis gas generatingtemperature (e.g., between about 400° C. and about 1200° C.). In someembodiments composition of produced synthesis gas may be affected byformation temperature, by the temperature of the formation adjacent tosynthesis gas production wells, and/or by residence time of thesynthesis gas components. A relatively low synthesis gas generationtemperature may produce a synthesis gas having a high H₂ to CO ratio,but the produced synthesis gas may also include a large portion of othergases such as water, CO₂, and methane. A relatively high formationtemperature may produce a synthesis gas having a H₂ to CO ratio thatapproaches 1, and the stream may include mostly (and in some casessubstantially only) H₂ and CO. If the synthesis gas generating fluid issubstantially pure steam, then the H₂ to CO ratio may approach 1 atrelatively high temperatures. At a formation temperature of about 700°C., the formation may produce a synthesis gas with a H₂ to CO ratio ofabout 2 at a certain pressure. The composition of the synthesis gastends to depend on the nature of the synthesis gas generating fluid.

Synthesis gas generation is generally an endothermic process. Heat maybe added to a portion of a formation during synthesis gas production tokeep formation temperature at a desired synthesis gas generatingtemperature or above a minimum synthesis gas generating temperature.Heat may be added to the formation from heat sources, from oxidationreactions within the portion, and/or from introducing synthesis gasgenerating fluid into the formation at a higher temperature than thetemperature of the formation.

An oxidant may be introduced into a portion of the formation withsynthesis gas generating fluid. The oxidant may exothermically reactwith carbon within the portion of the formation to heat the formation.Oxidation of carbon within a formation may allow a portion of aformation to be economically heated to relatively high synthesis gasgenerating temperatures. The oxidant may also be introduced into theformation without synthesis gas generating fluid to heat the portion.Using an oxidant, or an oxidant and heat sources, to heat the portion ofthe formation may be significantly more favorable than heating theportion of the formation with only the heat sources. The oxidant may be,but is not limited to, air, oxygen, or oxygen enriched air. The oxidantmay react with carbon in the formation to produce CO₂ and/or CO. The useof air, or oxygen enriched air (i.e., air with an oxygen content greaterthan 21% by volume), to generate heat within the formation may cause asignificant portion of N₂ to be present in produced synthesis gas.Temperatures in the formation may be maintained below temperaturesneeded to generate oxides of nitrogen (NO_(x)), so that little or noNO_(x) compounds may be present in produced synthesis gas.

A mixture of steam and oxygen, or steam and air, may be substantiallycontinuously injected into a formation. If injection of steam and oxygenis used for synthesis gas production, the oxygen may be produced on siteby electrolysis of water utilizing direct current output of a fuel cell.H₂ produced by the electrolysis of water may be used as a fuel streamfor the fuel cell. O₂ produced by the electrolysis of water may beinjected into the hot formation to raise a temperature of the formation.

Heat sources and/or production wells within a formation for pyrolyzingand producing pyrolysis fluids from the formation may be utilized fordifferent purposes during synthesis gas production. A well that was usedas a heat source or a production well during pyrolysis may be used as aninjection well to introduce synthesis gas producing fluid into theformation. A well that was used as a heat source or a production wellduring pyrolysis may be used as a production well during synthesis gasgeneration. A well that was used as a heat source or a production wellduring pyrolysis may be used as a heat source to heat the formationduring synthesis gas generation. Synthesis gas production wells may bespaced further apart than pyrolysis production wells because of therelatively high, substantially uniform permeability of the formation.Synthesis gas production wells may be heated to relatively hightemperatures so that a portion of the formation adjacent to theproduction well is at a temperature that will produce a desiredsynthesis gas.composition. Comparatively, pyrolysis fluid productionwells may not be heated at all, or may only be heated to a temperaturethat will inhibit condensation of pyrolysis fluid within the productionwell.

Synthesis gas may be produced from a dipping formation from wells usedduring pyrolysis of the formation. As shown in FIG. 4, synthesis gasproduction wells 206 may be located above and down dip from an injectionwell 202. Hot synthesis gas producing fluid may be introduced intoinjection well 202. Hot synthesis gas fluid that moves down dip maygenerate synthesis gas that is produced through synthesis gas productionwells 206. Synthesis gas generating fluid that moves up dip may generatesynthesis gas in a portion of the formation that is at synthesis gasgenerating temperatures. A portion of the synthesis gas generating fluidand generated synthesis gas that moves up dip above the portion of theformation at synthesis gas generating temperatures may heat adjacentportions of the formation. The synthesis gas generating fluid that movesup dip may condense, heat adjacent portions of formation, and flowdownwards towards or into a portion of the formation at synthesis gasgenerating temperature. The synthesis gas generating fluid may thengenerate additional synthesis gas.

Synthesis gas generating fluid may be any fluid capable of generating H₂and CO within a heated portion of a formation. Synthesis gas generatingfluid may include water, O₂, air, CO₂, hydrocarbon fluids, orcombinations thereof. Water may be introduced into a formation as aliquid or as steam. Water may react with carbon in a formation toproduce H₂, CO, and CO₂. CO₂ may react with hot carbon to form CO. Airand O₂ maybe oxidants that react with carbon in a formation to generateheat and form CO₂, CO, and other compounds. Hydrocarbon fluids may reactwithin a formation to form H₂, CO, CO₂, H₂O, coke, methane and/or otherlight hydrocarbons. Introducing low carbon number hydrocarbons (i.e.,compounds with carbon numbers less than 5) may produce additional H₂within the formation. Adding higher carbon number hydrocarbons to theformation may increase an energy content of generated synthesis gas byhaving a significant methane and other low carbon number compoundsfraction within the synthesis gas.

Water provided as a synthesis gas generating fluid may be derived fromnumerous different sources. Water may be produced during a pyrolysisstage of treating a formation. The water may include some entrainedhydrocarbon fluids. Such fluid may be used as synthesis gas generatingfluid. Water that includes hydrocarbons may advantageously generateadditional H₂ when used as a synthesis gas generating fluid. Waterproduced from water pumps that inhibit water flow into a portion offormation being subjected to an in situ conversion process may providewater for synthesis gas generation. A low rank kerogen resource orhydrocarbons having a relatively high water content (i.e. greater thanabout 20% H₂O by weight) may generate a large amount of water and/or CO₂if subjected to an in situ conversion process. The water and CO₂produced by subjecting a low rank kerogen resource to an in situconversion process may be used as a synthesis gas generating fluid.

Reactions involved in the formation of synthesis gas may include, butare not limited to:

C+H₂O⇄H₂+CO  (1)

C+2H₂O⇄2H₂+CO₂  (2)

C+CO₂⇄2CO  (3)

Thermodynamics allows the following reactions to proceed:

2C+2H₂O⇄CH₄+CO₂  (4)

C+2H₂⇄CH₄  (5)

However, kinetics of the reactions are slow in certain embodiments sothat relatively low amounts of methane are formed at formationconditions from Reactions (4) and (5).

In the presence of oxygen, the following reaction may take place togenerate carbon dioxide and heat:

C+O₂→CO₂  (6)

Equilibrium gas phase compositions of coal in contact with steam mayprovide an indication of the compositions of components produced in aformation during synthesis gas generation. Equilibrium composition datafor H₂, carbon monoxide, and carbon dioxide may be used to determineappropriate operating conditions such as temperature that may be used toproduce a synthesis gas having a selected composition. Equilibriumconditions may be approached within a formation due to a high,substantially uniform permeability of the formation. Composition dataobtained from synthesis gas production may in many instances deviate byless than 10% from equilibrium values.

In one embodiment, a composition of the produced synthesis gas can bechanged by injecting additional components into the formation along withsteam. Carbon dioxide may be provided in the synthesis gas generatingfluid to substantially inhibit production of carbon dioxide producedfrom the formation during synthesis gas generation. The carbon dioxidemay shift the equilibrium of reaction (2) to the left, thus reducing theamount of carbon dioxide generated from formation carbon. The carbondioxide may also react with carbon in the formation to generate carbonmonoxide. Carbon dioxide may be separated from the synthesis gas and maybe re-injected into the formation with the synthesis gas generatingfluid. Addition of carbon dioxide in the synthesis gas generating fluidmay, however, reduce the production of hydrogen.

FIG. 29 depicts a schematic diagram of use of water recovered frompyrolysis fluid production being used to generate synthesis gas. Heatsource 801 with electric heater 803 produces pyrolysis fluid 807 fromfirst section 805 of the formation. Produced pyrolysis fluid 807 may besent to separator 809. Separator 809 may include a number of individualseparation units and processing units that produce aqueous stream 811,vapor stream 813, and hydrocarbon condensate stream 815. Aqueous stream811 from the separator 809 may be combined with synthesis gas generatingfluid 818 to form synthesis gas generating fluid 821. Synthesis gasgenerating fluid 821 may be provided to injection well 817 andintroduced to second portion 819 of the formation. Synthesis gas 823 maybe produced from synthesis gas production well 825.

FIG. 30 depicts a schematic diagram of an embodiment of a system forsynthesis gas production in which carbon dioxide from produced synthesisgas is injected into a formation. Synthesis gas 830 may be produced fromformation 832 through production well 834. Gas separation unit 836 mayseparate a portion of carbon dioxide from the synthesis gas 830 toproduce CO₂ stream 838 and remaining synthesis gas stream 840. The CO₂stream 838 may be mixed with synthesis gas producing fluid stream 842that is introduced into the formation 832 through injection well 837,and/or the CO₂ may be separately introduced into the formation. This maylimit conversion of carbon within the formation to CO₂ and/or mayincrease an amount of CO generated within the formation.

Synthesis gas generating fluid may be introduced into a formation in avariety of different ways. Steam may be injected into a heatedhydrocarbon containing formation at a lowermost portion of the heatedformation. Alternatively, in a steeply dipping formation, steam may beinjected up dip with synthesis gas production down dip. The injectedsteam may pass through the remaining hydrocarbon containing formation toa production well. In addition, endothermic heat of reaction may beprovided to the formation with heat sources disposed along a path of theinjected steam. In alternate embodiments, steam may be injected at aplurality of locations along the hydrocarbon containing formation toincrease penetration of the steam throughout the formation. A line drivepattern of locations may also be utilized. The line drive pattern mayinclude alternating rows of steam injection wells and synthesis gasproduction wells.

At relatively low pressures, and temperatures below about 400° C.,synthesis gas reactions are relatively slow. At relatively lowpressures, and temperatures between about 400° C. and about 700° C.,Reaction (2) tends to be the predominate reaction and the synthesis gascomposition is primarily hydrogen and carbon dioxide. At relatively lowpressures, and temperatures greater than about 700° C., Reaction (1)tends to be the predominate reaction and the synthesis gas compositionis primarily hydrogen and carbon monoxide.

Advantages of a lower temperature synthesis gas reaction may includelower heat requirements, cheaper metallurgy and less endothermicreactions (especially when methane formation takes place). An advantageof a higher temperature synthesis gas reaction is that hydrogen andcarbon monoxide may be used as feedstock for other processes (e.g.,Fischer-Tropsch processes).

A pressure of the hydrocarbon containing formation may be maintained atrelatively high pressures during synthesis gas production. The pressuremay range from atmospheric pressure to a lithostatic pressure of theformation. Higher formation pressures may allow generation ofelectricity by passing produced synthesis gas through a turbine. Higherformation pressures may allow for smaller collection conduits totransport produced synthesis gas, and reduced downstream compressionrequirements on the surface.

In some embodiments, synthesis gas may be produced from a portion of aformation in a substantially continuous manner. The portion may beheated to a desired synthesis gas generating temperature. A synthesisgas generating fluid may be introduced into the portion. Heat may beadded to, or generated within, the portion of the formation duringintroduction of the synthesis gas generating fluid to the portion. Theadded heat compensates for the loss of heat due to the endothermicsynthesis gas reactions as well as heat losses to the top and bottomlayers, etc. In other embodiments, synthesis gas may be produced in asubstantially batch manner. The portion of the formation may be heated,or heat may be generated within the portion, to raise a temperature ofthe portion to a high synthesis gas generating temperature. Synthesisgas generating fluid may then be added to the portion until generationof synthesis gas reduces the temperature of the formation below atemperature that produces a desired synthesis gas composition.Introduction of the synthesis gas generating fluid may then be stopped.The cycle may be repeated by reheating the portion of the formation tothe high synthesis gas generating temperature and adding synthesis gasgenerating fluid after obtaining the high synthesis gas generatingtemperature. Composition of generated synthesis gas may be monitored todetermine when addition of synthesis gas generating fluid to theformation should be stopped.

FIG. 31 illustrates a schematic of an embodiment of a continuoussynthesis gas production system. FIG. 31 includes a formation with heatinjection wellbore 850 and heat injection wellbore 852. The wellboresmay be members of a larger pattern of wellbores placed throughout aportion of the formation. A portion of a formation may be heated tosynthesis gas generating temperatures by heating the formation with heatsources, by injecting an oxidizing fluid, or by a combination thereof.Oxidizing fluid 854, such as air or oxygen, and synthesis gas generatingfluid 856, such as steam, may be injected into wellbore 850. In oneembodiment, the ratio of oxygen to steam may be approximately 1:2 toapproximately 1:10, or approximately 1:3 to approximately 1:7 (e.g.,about 1:4).

In situ combustion of hydrocarbons may heat region 858 of the formationbetween wellbores 850 and 852. Injection of the oxidizing fluid may heatregion 858 to a particular temperature range, for example, between about600° C. and about 700° C. The temperature may vary, however, dependingon a desired composition of the synthesis gas. An advantage of thecontinuous production method may be that the temperature across region858 may be substantially uniform and substantially constant with timeonce the formation has reached substantial thermal equilibrium.Continuous production may also eliminate a need for use of valves toreverse injection directions on a substantially frequent basis. Further,continuous production may reduce temperatures near the injections wellsdue to endothermic cooling from the synthesis gas reaction that mayoccur in the same region as oxidative heating. The substantiallyconstant temperature may allow for control of synthesis gas composition.Produced synthesis gas 860 may exit continuously from wellbore 852.

In an embodiment, it may be desirable to use oxygen rather than air asoxidizing fluid 854 in continuous production. If air is used, nitrogenmay need to be separated from the synthesis gas. The use of oxygen asoxidizing fluid 854 may increase a cost of production due to the cost ofobtaining substantially pure oxygen. The cryogenic nitrogen by-productobtained from an air separation plant used to produce the requiredoxygen may, however, be used in a heat exchanger to condensehydrocarbons from a hot vapor stream produced during pyrolysis ofhydrocarbons. The pure nitrogen may also be used for ammonia production.

FIG. 32 illustrates a schematic of an embodiment of a batch productionof synthesis gas in a hydrocarbon containing formation. Wellbore 870 andwellbore 872 may be located within a portion of the formation. Thewellbores may be members of a larger pattern of wellbores throughout theportion of the formation. Oxidizing fluid 874, such as air or oxygen,may be injected into wellbore 870. Oxidation of hydrocarbons may heatregion 876 of a formation between wellbores 870 and 872. Injection ofair or oxygen may continue until an average temperature of region 876 isat a desired temperature (e.g., between about 900° C. and about 1000°C.). Higher or lower temperatures may also be developed. A temperaturegradient may be formed in region 876 between wellbore 870 and wellbore872. The highest temperature of the gradient may be located proximate tothe injection wellbore 870.

When a desired temperature has been reached, or when oxidizing fluid hasbeen injected for a desired period of time, oxidizing fluid injectionmay be lessened and/or ceased. A synthesis gas generating fluid 877,such as steam or water, may be injected into the injection wellbore 872to produce synthesis gas. A back pressure of the injected steam or waterin the injection wellbore may force the synthesis gas produced andun-reacted steam across region 876. A decrease in average temperature ofregion 876 caused by the endothermic synthesis gas reaction may bepartially offset by the temperature gradient in region 876 in adirection indicated by arrow 878. Product stream 880 may be producedthrough heat source wellbore 870. If the composition of the productdeviates substantially from a desired composition, then steam injectionmay cease, and air or oxygen injection may be reinitiated.

In one embodiment, synthesis gas of a selected composition may beproduced by blending synthesis gas produced from different portions ofthe formation. A first portion of a formation may be heated by one ormore heat sources to a first temperature sufficient to allow generationof synthesis gas having a H₂ to carbon monoxide ratio of less than theselected H₂ to carbon monoxide ratio (e.g., about 1 or 2). A firstsynthesis gas generating fluid may be provided to the first portion togenerate a first synthesis gas. The first synthesis gas may be producedfrom the formation. A second portion of the formation may be heated byone or more heat sources to a second temperature sufficient to allowgeneration of synthesis gas having a H₂ to carbon monoxide ratio ofgreater than the selected H₂ to carbon monoxide ratio (e.g., a ratio of3 or more). A second synthesis gas generating fluid may be provided tothe second portion to generate a second synthesis gas. The secondsynthesis gas may be produced from the formation. The first synthesisgas may be blended with the second synthesis gas to produce a blendsynthesis gas having a desired H₂ to carbon monoxide ratio.

The first temperature may be substantially different than the secondtemperature. Alternatively, the first and second temperatures may beapproximately the same temperature. For example, a temperaturesufficient to allow generation of synthesis gas having differentcompositions may vary depending on compositions of the first and secondportions and/or prior pyrolysis of hydrocarbons within the first andsecond portions. The first synthesis gas generating fluid may havesubstantially the same composition as the second synthesis gasgenerating fluid. Alternatively, the first synthesis gas generatingfluid may have a different composition than the second synthesis gasgenerating fluid. Appropriate first and second synthesis gas generatingfluids may vary depending upon, for example, temperatures of the firstand second portions, compositions of the first and second portions, andprior pyrolysis of hydrocarbons within the first and second portions.

In addition, synthesis gas having a selected ratio of H₂ to carbonmonoxide may be obtained by controlling the temperature of theformation. In one embodiment, the temperature of an entire portion orsection of the formation may be controlled to yield synthesis gas with aselected ratio. Alternatively, the temperature in or proximate to asynthesis gas production well may be controlled to yield synthesis gaswith the selected ratio.

In one embodiment, synthesis gas having a selected ratio of H₂ to carbonmonoxide may be obtained by treating produced synthesis gas at thesurface. First, the temperature of the formation may be controlled toyield synthesis gas with a ratio different than a selected ratio. Forexample, the formation may be maintained at a relatively hightemperature to generate a synthesis gas with a relatively low H₂ tocarbon monoxide ratio (e.g., the ratio may approach 1 under certainconditions). Some or all of the produced synthesis gas may then beprovided to a shift reactor (shift process) at the surface. Carbonmonoxide reacts with water in the shift process to produce H₂ and carbondioxide. Therefore, the shift process increases the H₂ to carbonmonoxide ratio. The carbon dioxide may then be separated to obtain asynthesis gas having a selected H₂ to carbon monoxide ratio.

In one embodiment, produced synthesis gas 918 may be used for productionof energy. In FIG. 33, treated gases 920 may be routed from treatmentsection 900 to energy generation unit 902 for extraction of usefulenergy. Energy may be extracted from the combustible gases generally byoxidizing the gases to produce heat and converting a portion of the heatinto mechanical and/or electrical energy. Alternatively, energygeneration unit 902 may include a fuel cell that produces electricalenergy. In addition, energy generation unit 902 may include, forexample, a molten carbonate fuel cell or another type of fuel cell, aturbine, a boiler firebox, or a down hole gas heater. Producedelectrical energy 904 may be supplied to power grid 906. A portion ofthe produced electricity 908 may be used to supply energy to electricalheating elements 910 that heat formation 912.

In one embodiment, energy generation unit 902 may be a boiler firebox. Afirebox may include a small refractory-lined chamber, built wholly orpartly in the wall of a kiln, for combustion of fuel. Air or oxygen 914may be supplied to energy generation unit 902 to oxidize the producedsynthesis gas. Water 916 produced by oxidation of the synthesis gas maybe recycled to the formation to produce additional synthesis gas.

The produced synthesis gas may also be used as a fuel in down hole gasheaters. Down hole gas heaters, such as a flameless combustor asdisclosed herein, may be configured to heat a hydrocarbon containingformation. In this manner, a thermal conduction process may besubstantially self-reliant and/or may substantially reduce or eliminatea need for electricity. Because flameless combustors may have a thermalefficiency approaching 90%, an amount of carbon dioxide released to theenvironment may be less than an amount of carbon dioxide released to theenvironment from a process using fossil-fuel generated electricity toheat the hydrocarbon containing formation.

Carbon dioxide may be produced by both pyrolysis and synthesis gasgeneration. Carbon dioxide may also be produced by energy generationprocesses and/or combustion processes. Net release of carbon dioxide tothe atmosphere from an in situ conversion process for hydrocarbons maybe reduced by utilizing the produced carbon dioxide and/or by storingcarbon dioxide within the formation. For example, a portion of carbondioxide produced from the formation may be utilized as a flooding agentor as a feedstock for producing chemicals.

In one embodiment, the energy generation process may produce a reducedamount of emissions by sequestering carbon dioxide produced duringextraction of useful energy. For example, emissions from an energygeneration process may be reduced by storing an amount of carbon dioxidewithin a hydrocarbon containing formation. The amount of stored carbondioxide may be approximately equivalent to that in an exit stream fromthe formation.

FIG. 33 illustrates a reduced emission energy process. Carbon dioxide928 produced by energy generation unit 902 may be separated from fluidsexiting the energy generation unit. Carbon dioxide may be separated fromH₂ at high temperatures by using a hot palladium film supported onporous stainless steel or a ceramic substrate, or high temperaturepressure swing adsorption. The carbon dioxide may be sequestered inspent hydrocarbon containing formation 922, injected into oil producingfields 924 for enhanced oil recovery by improving mobility andproduction of oil in such fields, sequestered into a deep hydrocarboncontaining formation 926 containing methane by adsorption and subsequentdesorption of methane, or re-injected 928 into a section of theformation through a synthesis gas production well to produce carbonmonoxide. Carbon dioxide leaving the energy generation unit may besequestered in a dewatered coal bed methane reservoir. The water forsynthesis gas generation may come from dewatering a coal bed methanereservoir. Additional methane can also be produced by alternating carbondioxide and nitrogen. An example of a method for sequestering carbondioxide is illustrated in U.S. Pat. No. 5,566,756 to Chaback et al.,which is incorporated by reference as if fully set forth herein.Additional energy may be utilized by removing heat from the carbondioxide stream leaving the energy generation unit.

In one embodiment, it may be desirable to cool a hot spent formationbefore sequestration of carbon dioxide. For example, a higher quantityof carbon dioxide may be adsorbed in a coal formation at lowertemperatures. In addition, cooling a formation may strengthen aformation. The spent formation may be cooled by introducing water intothe formation. The steam produced may be removed from the formation. Thegenerated steam may be used for any desired process. For example, thesteam may be provided to an adjacent portion of a formation to heat theadjacent portion or to generate synthesis gas.

In one embodiment, a spent hydrocarbon containing formation may bemined. The mined material may in some embodiments be used formetallurgical purposes such as a fuel for generating high temperaturesduring production of steel. Pyrolysis of a coal formation maysubstantially increase a rank of the coal. After pyrolysis, the coal maybe substantially transformed to a coal having characteristics ofanthracite. A spent hydrocarbon containing formation may have athickness of 30 m or more. Anthracite coal seams, which are typicallymined for metallurgical uses, may be only about one meter in thickness.

FIG. 34 illustrates an embodiment in which fluid produced from pyrolysismay be separated into a fuel cell feed stream and fed into a fuel cellto produce electricity. The embodiment may include carbon containingformation 940 with producing well 942 configured to produce synthesisgas and heater well 944 with electric heater 946 configured to producedpyrolysis fluid 948. In one embodiment, pyrolysis fluid may include H₂and hydrocarbons with carbon numbers less than 5. Pyrolysis fluid 948produced from heater well 944 may be fed to gas membrane separationsystem 950 to separate H₂ and hydrocarbons with carbon numbers less than5. Fuel cell feed stream 952, which may be substantially composed of H₂,may be fed into fuel cell 954. Air feed stream 956 may be fed into fuelcell 954. Nitrogen stream 958 may be vented from fuel cell 954.Electricity 960 produced from the fuel cell may be routed to a powergrid. Electricity 962 may also be used to power electric heaters 946 inheater wells 944. Carbon dioxide 965 may be injected into formation 940.

Hydrocarbons having carbon numbers of 4, 3, and 1 typically have fairlyhigh market values. Separation and selling of these hydrocarbons may bedesirable. Typically ethane may not be sufficiently valuable to separateand sell in some markets. Ethane may be sent as part of a fuel stream toa fuel cell or ethane may be used as a hydrocarbon fluid component of asynthesis gas generating fluid. Ethane may also be used as a feedstockto produce ethene. In some markets, there may be no market for anyhydrocarbons having carbon numbers less than 5. In such a situation, allof the hydrocarbon gases produced during pyrolysis may be sent to fuelcells or be used as hydrocarbon fluid components of a synthesis gasgenerating fluid.

Pyrolysis fluid 964, which may be substantially composed of hydrocarbonswith carbon numbers less than 5, may be injected into formation 940.When the hydrocarbons contact the formation, hydrocarbons may crackwithin the formation to produce methane, H₂, coke, and olefins such asethene and propylene. In one embodiment, the production of olefins maybe increased by heating the temperature of the formation to the upperend of the pyrolysis temperature range and by injecting hydrocarbonfluid at a relatively high rate. In this manner, residence time of thehydrocarbons in the formation may be reduced and dehydrogenatedhydrocarbons may tend to form olefins rather than cracking to form H₂and coke. Olefin production may also be increased by reducing formationpressure.

In one embodiment, electric heater 946 may be a flameless distributedcombustor. At least a portion of H₂ produced from the formation may beused as fuel for the flameless distributed combustor.

In addition, in some embodiments, heater well 944 may heat the formationto a synthesis gas generating temperature range. Pyrolysis fluid 964,which may be substantially composed of hydrocarbons with carbon numbersless than 5, may be injected into the formation 940. When thehydrocarbons contact the formation, the hydrocarbons may crack withinthe formation to produce methane, H₂, and coke.

FIG. 35 depicts an embodiment of a synthesis gas generating process fromhydrocarbon containing formation 976 with flameless distributedcombustor 996. Synthesis gas 980 produced from production well 978 maybe fed into gas separation plant 984 where carbon dioxide 986 may beseparated from synthesis gas 980. First portion 990 of carbon dioxidemay be routed to a formation for sequestration. Second portion 992 ofcarbon dioxide may also be injected into the formation with synthesisgas generating fluid. Portion 993 of synthesis gas 988 may be fed toheater well 994 for combustion in distributed burner 996 to produce heatfor the formation. Portion 998 of synthesis gas 988 may be fed to fuelcell 1000 for the production of electricity. Electricity 1002 may berouted to a power grid. Steam 1004 produced in the fuel cell and steam1006 produced from combustion in the distributed burner may be fed tothe formation for generation of synthesis gas.

In one embodiment, carbon dioxide generated with pyrolysis fluids asdescribed herein may be sequestered in a hydrocarbon containingformation. FIG. 36 illustrates in situ pyrolysis in hydrocarboncontaining formation 1020. Heater well 1022 with electric heater 1024may be disposed in formation 1020. Pyrolysis fluids 1026 may be producedfrom formation 1020 and fed into gas separation unit 1028 where carbondioxide 1030 may be separated from pyrolysis fluids 1032. Portion 1034of carbon dioxide 1030 may be stored in formation 1036. The carbondioxide may be sequestered in spent hydrocarbon containing formation1038, injected into oil producing fields 1040 for enhanced oil recovery,or sequestered into coal bed 1042. Alternatively, carbon dioxide mayalso be re-injected 1044 into a section of formation 1020 through asynthesis gas production well to produce carbon monoxide. At least aportion of electricity 1035 may be used to power one or more electricheaters.

In one embodiment, fluid produced from pyrolysis of at least somehydrocarbons in a formation may be fed into a reformer to producesynthesis gas. The synthesis gas may be fed into a fuel cell to produceelectricity. In addition, carbon dioxide generated by the fuel cell maybe sequestered to reduce an amount of emissions generated by theprocess.

As shown in FIG. 37, heater well 1060 may be located within hydrocarboncontaining formation 1062. Additional heater wells may also be locatedwithin the formation. Heater well 1060 may include electric heater 1064.Pyrolysis fluid 1066 produced from the formation may be fed to areformer, such as steam reformer 1068, to produce synthesis gas 1070. Aportion of the pyrolysis products may be used as fuel in the reformer.Steam reformer 1068 may include a catalyst material that promotes thereforming reaction and a burner to supply heat for the endothermicreforming reaction. A steam source may be connected to the reformersection to provide steam for the reforming reaction. The burner mayoperate at temperatures well above that required by the reformingreaction and well above the operating temperatures of fuel cells. Assuch, it may be desirable to operate the burner as a separate unitindependent of the fuel cell.

Alternatively, a reformer may include multiple tubes that may be made ofrefractory metal alloys. Each tube may include a packed granular orpelletized material having a reforming catalyst as a surface coating. Adiameter of the tubes may vary from between about 9 cm and about 16 cm,and the heated length of the tube may normally be between about 6 m andabout 12 m. A combustion zone may be provided external to the tubes, andmay be formed in the burner. A surface temperature of the tubes may bemaintained by the burner at a temperature of about 900° C. to ensurethat the hydrocarbon fluid flowing inside the tube is properly catalyzedwith steam at a temperature between about 500° C. and about 700° C. Atraditional tube reformer may rely upon conduction and convection heattransfer within the tube to distribute heat for reforming.

In addition, hydrocarbon fluids, such as pyrolysis fluids, may bepre-processed prior to being fed to a reformer. The reformer may beconfigured to transform the pyrolysis fluids into simpler reactantsprior to introduction to a fuel cell. For example, pyrolysis fluids maybe pre-processed in a desulfurization unit. Subsequent topre-processing, the pyrolysis fluids may be provided to a reformer and ashift reactor to produce a suitable fuel stock for a H₂ fueled fuelcell.

The synthesis gas produced by the reformer may include any of thecomponents described above, such as methane. The produced synthesis gas1070 may be fed to fuel cell 1072. A portion of electricity 1074produced by the fuel cell may be sent to a power grid. In addition, aportion of electricity 1076 may be used to power electric heater 1064.Carbon dioxide 1078 exiting the fuel cell may be routed to sequestrationarea 1080.

Alternatively, in one embodiment, pyrolysis fluids 1066 produced fromthe formation may be fed to reformer 1068 that produces carbon dioxidestream 1082 and H₂ stream 1070. For example, the reformer may include aflameless distributed combustor for a core, and a membrane. The membranemay allow only H₂ to pass through the membrane resulting in separationof the H₂ and carbon dioxide. The carbon dioxide may be routed tosequestration area 1080.

Synthesis gas produced from a formation may be converted to heaviercondensable hydrocarbons. For example, a Fischer-Tropsch hydrocarbonsynthesis process may be used for conversion of synthesis gas. AFischer-Tropsch process may include converting synthesis gas tohydrocarbons. The process may use elevated temperatures, normal orelevated pressures, and a catalyst, such as magnetic iron oxide or acobalt catalyst. Products produced from a Fischer-Tropsch process mayinclude hydrocarbons having a broad molecular weight distribution andmay include branched and unbranched paraffins. Products from aFischer-Tropsch process may also include considerable quantities ofolefins and oxygen-containing organic compounds. An example of aFischer-Tropsch reaction may be illustrated by the following:

(n+2)CO+(2n+5)H₂⇄CH₃(—CH₂—)nCH₃+(n+2)H₂O  (7)

A hydrogen to carbon monoxide ratio for synthesis gas used as a feed gasfor a Fischer-Tropsch reaction may be about 2:1. In certain embodimentsthe ratio may range from approximately 1.8:1 to 2.2:1. Higher or lowerratios may be accommodated by certain Fischer-Tropsch systems.

FIG. 38 illustrates a flowchart of a Fischer-Tropsch process that usessynthesis gas produced from a hydrocarbon containing formation as a feedstream. Hot formation 1090 may be used to produce synthesis gas having aH₂ to CO ratio of approximately 2:1. The proper ratio may be produced byoperating synthesis production wells at approximately 700° C., or byblending synthesis gas produced from different sections of formation toobtain a synthesis gas having approximately a 2:1 H₂ to CO ratio.Synthesis gas generating fluid 1092 may be fed into the hot formation1090 to generate synthesis gas. H₂ and CO may be separated from thesynthesis gas produced from the hot formation 1090 to form feed stream1094. Feed stream 1094 may be sent to Fischer-Tropsch plant 1096. Feedstream 1094 may supplement or replace synthesis gas 1098 produced fromcatalytic methane reformer 1100.

Fischer-Tropsch plant 1096 may produce wax feed stream 1102. TheFischer-Tropsch synthesis process that produces wax feed stream 1102 isan exothermic process. Steam 1104 may be generated during theFischer-Tropsch process. Steam 1104 may be used as a portion ofsynthesis gas generating fluid 1092.

Wax feed stream 1102 produced from Fischer-Tropsch plant 1096 may besent to hydrocracker 1106. The hydrocracker may produce product stream1108. The product stream may include diesel, jet fuel, and/or naphthaproducts. Examples of methods for conversion of synthesis gas tohydrocarbons in a Fischer-Tropsch process are illustrated in U.S. Pat.No. 4,096,163 to Chang et al., U.S. Pat. No. 6,085,512 to Agee et al.,and U.S. Pat. No. 6,172,124 to Wolflick et al., which are incorporatedby reference as if fully set forth herein.

FIG. 39 depicts an embodiment of in situ synthesis gas productionintegrated with a Shell Middle Distillates Synthesis (SMDS)Fischer-Tropsch and wax cracking process. An example of a SMDS processis illustrated in U.S. Pat. No. 4,594,468 to Minderhoud, and isincorporated by reference as if fully set forth herein. A middledistillates hydrocarbon mixture may also be produced from producedsynthesis gas using the SMDS process as illustrated in FIG. 39. Middledistillates may designate hydrocarbon mixtures with a boiling pointrange that may correspond substantially with that of kerosene and gasoil fractions obtained in a conventional atmospheric distillation ofcrude oil material. The middle distillate boiling point range mayinclude temperatures between about 150° C. and about 360° C., with afractions boiling point between about 200° C. and about 360° C., and maybe referred to as gas oil. FIG. 39 depicts synthesis gas 1120, having aH₂ to carbon monoxide ratio of about 2:1, that may exit production well1128 and may be fed into SMDS plant 1122. In certain embodiments theratio may range from approximately 1.8:1 to 2.2:1. Products of the SMDSplant include organic liquid product 1124 and steam 1126. Steam 1126 maybe supplied to injection wells 1127. In this manner, steam may be usedas a feed for synthesis gas production. Hydrocarbon vapors may in somecircumstances be added to the steam.

FIG. 40 depicts an embodiment of in situ synthesis gas productionintegrated with a catalytic methanation process. For example, synthesisgas 1140 exiting production well 1142 may be supplied to catalyticmethanation plant 1144. In some embodiments, it may be desirable for thecomposition of produced synthesis gas, which may be used as a feed gasfor a catalytic methanation process, to have a H₂ to carbon monoxideratio of about three to one. Methane 1146 may be produced by catalyticmethanation plant 1144. Steam 1148 produced by plant 1144 may besupplied to injection well 1141 for production of synthesis gas.Examples of a catalytic methanation process are illustrated in U.S. Pat.Nos. 3,922,148 to Child; U.S. Pat. No. 4,130,575 to Jorn et al.; andU.S. Pat. No. 4,133,825 to Stroud et al., which are incorporated byreference as if fully set forth herein.

The synthesis gas produced may also be used as a feed for a process forproduction of methanol. Examples of processes for production of methanolare illustrated in U.S. Pat. No. 4.407,973 to van Dijk et al., U.S. Pat.No. 4,927,857 to McShea, III et al., and U.S. Pat. No. 4,994,093 toWetzel et al., which are incorporated by reference as if fully set forthherein. The produced synthesis gas may also be used as a feed gas for aprocess that may convert synthesis gas to gasoline and a process thatmay convert synthesis gas to diesel fuel. Examples of process forproducing engine fuels are illustrated in U.S. Pat. No. 4,076,761 toChang et al., U.S. Pat. No. 4,138,442 to Chang et al., and U.S. Pat. No.4,605,680 to Beuther et al., which are incorporated by reference as iffully set forth herein.

In one embodiment, produced synthesis gas may be used as a feed gas forproduction of ammonia and urea as illustrated by FIGS. 41 and 42.Ammonia may be synthesized by the Haber-Bosch process, which involvessynthesis directly from N₂ and H₂ according to the reaction:

N₂+3H₂⇄2NH₃  (8)

The N₂ and H₂ may be combined, compressed to high pressure, (e.g., fromabout 80 bars to about 220 bars), and then heated to a relatively hightemperature. The reaction mixture may be passed over a catalyst composedsubstantially of iron, where ammonia production may occur. Duringammonia synthesis, the reactants (i.e., N₂ and H₂) and the product(i.e., ammonia) may be in equilibrium. In this manner, the total amountof ammonia produced may be increased by shifting the equilibrium towardsproduct formation. Equilibrium may be shifted to product formation byremoving ammonia from the reaction mixture as it is produced.

Removal of the ammonia may be accomplished by cooling the gas mixture toa temperature between about (−5)° C. to about 25° C. In this temperaturerange, a two-phase mixture may be formed with ammonia in the liquidphase and N₂ and H₂ in the gas phase. The ammonia may be separated fromother components of the mixture. The nitrogen and hydrogen may besubsequently reheated to the operating temperature for ammoniaconversion and passed through the reactor again.

Urea may be prepared by introducing ammonia and carbon dioxide into areactor at a suitable pressure, (e.g., from about 125 bars absolute toabout 350 bars absolute), and at a suitable temperature, (e.g., fromabout 160° C. to about 250° C.). Ammonium carbamate may be formedaccording to the following reaction:

2NH₃+CO₂→NH₂(CO₂)NH₄  (9)

Urea may be subsequently formed by dehydrating the ammonium carbamateaccording to the following equilibrium reaction:

NH₂(CO₂)NH₄⇄NH₂(CO)NH₂+H₂O  (10)

The degree to which the ammonia conversion takes place may depend on,for example, the temperature and the amount of excess ammonia. Thesolution obtained as the reaction product may substantially includeurea, water, ammonium carbamate and unbound ammonia. The ammoniumcarbamate and the ammonia may need to be removed from the solution. Onceremoved, they may be returned to the reactor. The reactor may includeseparate zones for the formation of ammonium carbamate and urea.However, these zones may also be combined into one piece of equipment.

According to one embodiment, a high pressure urea plant may operate suchthat the decomposition of the ammonium carbamate that has not beenconverted into urea and the expulsion of the excess ammonia may beconducted at a pressure between 15 bars absolute and 100 bars absolute.This may be considerably lower than the pressure in the urea synthesisreactor. The synthesis reactor may be operated at a temperature of about180° C. to about 210° C. and at a pressure of about 180 bars absolute toabout 300 bars absolute. Ammonia and carbon dioxide may be directly fedto the urea reactor. The NH₃/CO₂ molar ratio (N/C molar ratio) in theurea synthesis may generally be between about 3 and about 5. Theunconverted reactants may be recycled to the urea synthesis reactorfollowing expansion, dissociation, and/or condensation.

In one embodiment, an ammonia feed stream having a selected ratio of H₂to N₂ may be generated from a formation using enriched air. A synthesisgas generating fluid and an enriched air stream may be provided to theformation. The composition of the enriched air may be selected togenerate synthesis gas having the selected ratio of H₂ to N₂. In oneembodiment, the temperature of the formation may be controlled togenerate synthesis gas having the selected ratio.

In one embodiment, the H₂ to N₂ ratio of the feed stream provided to theammonia synthesis process may be approximately 3:1. In otherembodiments, the ratio may range from approximately 2.8:1 to 3.2:1. Anammonia synthesis feed stream having a selected H₂ to N₂ ratio may beobtained by blending feed streams produced from different portions ofthe formation.

In one embodiment, ammonia from the ammonia synthesis process may beprovided to a urea synthesis process to generate urea. Ammonia producedduring pyrolysis may be added to the ammonia generated from the ammoniasynthesis process. In another embodiment, ammonia produced duringhydrotreating may be added to the ammonia generated from the ammoniasynthesis process. Some of the carbon monoxide in the synthesis gas maybe converted to carbon dioxide in a shift process. The carbon dioxidefrom the shift process may be fed to the urea synthesis process. Carbondioxide generated from treatment of the formation may also be fed, insome instances, to the urea synthesis process.

FIG. 41 illustrates an embodiment of a method for production of ammoniaand urea from synthesis gas using membrane-enriched air. Enriched air1170 and steam, or water, 1172 may be fed into hot carbon containingformation 1174 to produce synthesis gas 1176 in a wet oxidation mode asdescribed herein.

In certain embodiments, enriched air 1170 is blended from air and oxygenstreams such that the nitrogen to hydrogen ratio in the producedsynthesis gas is about 1:3. The synthesis gas may be at a correct ratioof nitrogen and hydrogen to form ammonia. For example, it has beencalculated that for a formation temperature of 700° C., a pressure of 3bar absolute, and with 13,231 tons/day of char that will be convertedinto synthesis gas, one could inject 14.7 kilotons/day of air, 6.2kilotons/day of oxygen, and 21.2 kilotons/day of steam. This wouldresult in production of 2 billion cubic feet/day of synthesis gasincluding 5689 tons/day of steam, 16,778 tons/day of carbon monoxide,1406 tons/day of hydrogen, 18,689 tons/day of carbon dioxide, 1258tons/day of methane, and 11,398 tons/day of nitrogen. After a shiftreaction (to shift the carbon monoxide to carbon dioxide, and to produceadditional hydrogen), the carbon dioxide may be removed, the productstream may be methanated (to remove residual carbon monoxide), and thenone can theoretically produce 13,840 tons/day of ammonia and 1258tons/day of methane. This calculation includes the products producedfrom Reactions (4) and (5) above.

Enriched air may be produced from a membrane separation unit. Membraneseparation of air may be primarily a physical process. Based uponspecific characteristics of each molecule, such as size and permeationrate, the molecules in air may be separated to form substantially pureforms of nitrogen, oxygen, or combinations thereof.

In one embodiment, a membrane system may include a hollow tube filledwith a plurality of very thin membrane fibers. Each membrane fiber maybe another hollow tube in which air flows. The walls of the membranefiber may be porous and may be configured such that oxygen may permeatethrough the wall at a faster rate than nitrogen. In this manner, anitrogen rich stream may be allowed to flow out the other end of thefiber. Air outside the fiber and in the hollow tube may be oxygenenriched. Such air may be separated for subsequent uses such asproduction of synthesis gas from a formation.

In one embodiment, the purity of the nitrogen generated may becontrolled by variation of the flow rate and/or pressure of air throughthe membrane. Increasing air pressure may increase permeation of oxygenmolecules through a fiber wall. Decreasing flow rate may increase theresidence time of oxygen in the membrane and, thus, may increasepermeation through the fiber wall. Air pressure and flow rate may beadjusted to allow a system operator to vary the amount and purity of thenitrogen generated in a relatively short amount of time.

The amount of N₂ in the enriched air may be adjusted to provide a N:Hratio of about 3:1 for ammonia production. It may be desirable togenerate synthesis gas at a temperature that may favor the production ofcarbon dioxide over carbon monoxide. It may be advantageous for thetemperature of the formation to be between about 400° C. and about 550°C. In another embodiment, it may be desirable for the temperature of theformation to be between about 400° C. and about 450° C. Synthesis gasproduced at such low temperatures may be substantially composed of N₂,H₂, and carbon dioxide with little carbon monoxide.

As illustrated in FIG. 41, a feed stream for ammonia production may beprepared by first feeding synthesis gas stream 1176 into ammonia feedstream gas processing unit 1178. In ammonia feed stream gas processingunit 1178 the feed stream may undergo a shift reaction (to shift thecarbon monoxide to carbon dioxide, and to produce additional hydrogen).Carbon dioxide can also be removed from the feed stream, and the feedstream can be methanated (to remove residual carbon monoxide).

In certain embodiments carbon dioxide may be separated from the feedstream (or any gas stream) by absorption in an amine unit. Membranes orother carbon dioxide separation techniques/equipment may also be used toseparate carbon dioxide from a feed stream.

Ammonia feed stream 1180 may be fed to ammonia production facility 1182to produce ammonia 1184. Carbon dioxide 1186 exiting the gas separationunit 1178 (and/or carbon dioxide from other sources) may be fed, withammonia 1184, into urea production facility 1188 to produce urea 1190.

Ammonia and urea may be produced using a carbon containing formation,and using an O₂ rich stream and a N₂ rich stream. The O₂ rich stream andsynthesis gas generating fluid may be provided to a formation. Theformation may be heated, or partially heated, by oxidation of carbon inthe formation with the O₂ rich stream. H₂ in the synthesis gas, and N₂from the N₂ rich stream, may be provided to an ammonia synthesis processto generate ammonia.

FIG. 42 illustrates a flowchart of an embodiment for production ofammonia and urea from synthesis gas using cryogenically separated air.Air 2000 may be fed into cryogenic air separation unit 2002. Cryogenicseparation involves a distillation process that may occur attemperatures between about (−168)° C. and (−172)° C. In otherembodiments, the distillation process may occur at temperatures betweenabout (−165)° C. and (−175)° C. Air may liquefy in these temperatureranges. The distillation process may be operated at a pressure betweenabout 8 bars absolute and about 10 bars absolute. High pressures may beachieved by compressing air and exchanging heat with cold air exitingthe column. Nitrogen is more volatile than oxygen and may come off as adistillate product.

N₂ 2004 exiting the separator may be utilized in heat exchanger 2006 tocondense higher molecular weight hydrocarbons from pyrolysis stream 2008to remove lower molecular weight hydrocarbons from the gas phase into aliquid oil phase. Upgraded gas stream 2010 containing a highercomposition of lower molecular weight hydrocarbons than stream 2008 andliquid stream 2012, which includes condensed hydrocarbons, may exit heatexchanger 2006.

Oxygen 2014 from cryogenic separation unit 2002 and steam 2016, orwater, may be fed into hot carbon containing formation 2018 to producesynthesis gas 2020 in a continuous process as described herein. It isdesirable to generate synthesis gas at a temperature that favors theformation of carbon dioxide over carbon monoxide. It may be advantageousfor the temperature of the formation to be between about 400° C. andabout 550° C. In another embodiment, it may be desirable for thetemperature of the formation to be between about 400° C. and about 450°C. Synthesis gas 2020 may be substantially composed of H₂ and carbondioxide. Carbon dioxide may be removed from synthesis gas 2020 toprepare a feed stream for ammonia production using amine gas separationunit 2022. H₂ stream 2024 from the gas separation unit and N₂ stream2026 from the heat exchanger may be fed into ammonia production facility2028 to produce ammonia 2030. Carbon dioxide 2032 exiting the gasseparation unit and ammonia 2030 may be fed into urea productionfacility 2034 to produce urea 2036.

In one embodiment, an ammonia synthesis process feed stream may begenerated by feeding a gas containing N₂ and carbon dioxide to a carboncontaining formation. The gas may be flue gas or it may be gas generatedby an oxidation reaction of O₂ with carbon in another portion of theformation. The gas containing N₂ and carbon dioxide may be provided to acarbon containing formation. The carbon dioxide in the gas may adsorb inthe formation and be sequestered therein. An exit stream may be producedfrom the formation. The exit stream may have a substantially lowerpercentage of carbon dioxide than the gas entering the formation. Thenitrogen in the exit gas may be provided to an ammonia synthesisprocess. H₂ in synthesis gas from another portion of the formation maybe provided to the ammonia synthesis process.

FIG. 43 illustrates an embodiment of a method for preparing a nitrogenstream for an ammonia and urea process. Air 2060 may be injected intohot carbon containing formation 2062 to produce carbon dioxide byoxidation of carbon in the formation. In an embodiment, a heater may beconfigured to heat at least a portion of the carbon containing formationto a temperature sufficient to support oxidation of the carbon. Thetemperature sufficient to support oxidation may be, for example, about260° C. for coal. Stream 2064 exiting the hot formation may be composedsubstantially of carbon dioxide and nitrogen. Nitrogen may be separatedfrom carbon dioxide by passing the stream through cold spent carboncontaining formation 2066. Carbon dioxide may be preferentially adsorbedversus nitrogen in the cold spent formation 2066. For example, at 50° C.and 0.35 bars, the adsorption of carbon dioxide on a spent portion ofcoal may be about 72 m³/metric ton compared to about 15.4 m³/metric tonfor nitrogen. Nitrogen 2068 exiting the cold spent portion 2066 may besupplied to ammonia production facility 2070 with H₂ stream 2072 toproduce ammonia 2074. The H₂ stream may be obtained by methods disclosedherein, for example, the methods described in FIGS. 41 and 42.

FIG. 44 illustrates an embodiment of a system configured to treat arelatively permeable formation. Relatively permeable formation 2200 mayinclude heavy hydrocarbons. Production wells 2210 may be disposed inrelatively permeable formation 2200. Relatively permeable formation 2200may be enclosed between substantially impermeable layers 2204. An uppersubstantially impermeable layer 2204 may be referred to as an overburdenof formation 2200. A lower substantially impermeable layer 2204 may bereferred to as a base rock of formation 2200. The overburden and thebase rock may include different types of impermeable materials. Forexample, the overburden and/or the base rock may include shale or wetcarbonate (i.e., a carbonate without hydrocarbons in it).

Low temperature heat sources 2216 and high temperature heat sources 2218may be disposed in production well 2210. Low temperature heat sources2216 and high temperature heat sources 2218 may be configured asdescribed herein. Production well 2210 may be configured as describedherein. Low temperature heat source 2216 may generally refer to a heatsource, or heater, configured to provide heat to a selected mobilizationsection of formation 2200 substantially adjacent to the low temperatureheat source. The provided heat may be configured to heat some or all ofthe selected mobilization section to an average temperature within amobilization temperature range of the heavy hydrocarbons containedwithin formation 2200. The mobilization temperature range may be betweenabout 75° C. to about 150° C. A selected mobilization temperature may beabout 100° C. The mobilization temperature may vary, however, dependingon a viscosity of the heavy hydrocarbons contained within formation2200. For example, a higher mobilization temperature may be required tomobilize a higher viscosity fluid within formation 2200.

High temperature heat source 2218 may generally refer to a heat source,or heater, configured to provide heat to selected pyrolyzation section2202 of formation 2200 substantially adjacent to the heat source 2218.The provided heat may be configured to heat selected pyrolyzationsection 2202 to an average temperature within a pyrolization temperaturerange of the heavy hydrocarbons contained within formation 2200. Thepyrolization temperature range may be between about 270° C. to about400° C. A selected pyrolization temperature may be about 300° C. Thepyrolization temperature may vary, however, depending on formationcharacteristics, composition, pressure, and/or a desired quality of aproduct produced from formation 2200. A quality of the product may bedetermined based upon properties of the product, (e.g., the API gravityof the product). Pyrolyzation may include cracking of the heavyhydrocarbons into hydrocarbon fragments and/or lighter hydrocarbons.Pyrolyzation of the heavy hydrocarbons tends to upgrade the quality ofthe heavy hydrocarbons.

As shown in FIG. 44, mobilized fluids in formation 2200 may flow intoselected pyrolyzation section 2202 substantially by gravity. Themobilized fluids may be upgraded by pyrolysis in selected pyrolyzationsection 2202. Flow of the mobilized fluids may optionally be increasedby providing pressurizing fluid 2214 through conduit 2212 into formation2200. Pressurizing fluid 2214 may be a fluid configured to increase apressure in formation 2200 proximate to conduit 2212. The increasedpressure proximate to conduit 2212 may increase a flow of the mobilizedfluids in formation 2200 into selected pyrolyzation section 2202. Apressure of pressurizing fluid 2214 provided by conduit 2212 may bebetween about 7 bars absolute to about 70 bars absolute. The pressure ofpressurizing fluid 2214 may vary, however, depending on, for example, aviscosity of fluid within formation 2200 and/or a desired flow rate offluid into selected pyrolyzation section 2202. Pressurizing fluid 2214may be any gas that may not substantially oxidize the heavyhydrocarbons. For example, pressurizing fluid 2214 may include N₂, CO₂,CH₄, hydrogen, steam, etc.

Production wells 2210 may be configured to remove pyrolyzation fluidsand/or mobilized fluids from selected pyrolyzation section 2202.Formation fluids may be removed as a vapor. The formation fluids may befurther upgraded by high temperature heat source 2218 and lowtemperature heat source 2216 in production well 2210. Production well2210 may be further configured to control pressure in selectedpyrolyzation section 2202 to provide a pressure gradient so thatmobilized fluids flow into selected pyrolyzation section 2202 from theselected mobilization section. In some embodiments, pressure in selectedpyrolyzation section 2202 may be controlled to in turn control the flowof the mobilized fluids into selected pyrolyzation section 2202. By notheating the entire formation to pyrolyzation temperatures, the drainageprocess may produce a substantially higher ratio of energy producedversus energy input for the in situ conversion process.

In addition, pressure in relatively permeable formation 2200 may becontrolled to produce a desired quality of formation fluids. Forexample, the pressure in relatively permeable formation 2200 may beincreased to produce formation fluids with an increased API gravity ascompared to formation fluids produced at a lower pressure. Increasingthe pressure in relatively permeable formation 2200 may increase ahydrogen partial pressure in mobilized and/or pyrolyzation fluids. Theincreased hydrogen partial pressure in mobilized and/or pyrolyzationfluids may reduce heavy hydrocarbons in mobilized and/or pyrolyzationfluids. Reducing the heavy hydrocarbons may produce lighter, morevaluable hydrocarbons. An API gravity of the hydrogenated heavyhydrocarbons may be substantially higher than an API gravity of theun-hydrogenated heavy hydrocarbons.

In an embodiment, pressurizing fluid 2214 may be provided to formation2200 through a conduit disposed in/or proximate to production well 2210.The conduit may be configured to provide pressurizing fluid 2214 intoformation 2200 proximate to upper impermeable layer 2204.

In another embodiment, low temperature heat source 2216 may be turneddown and/or off in production wells 2210. The heavy hydrocarbons information 2200 may be mobilized by transfer of heat from selectedpyrolyzation section 2202 into an adjacent portion of formation 2200.Heat transfer from selected pyrolyzation section 2202 may besubstantially by conduction.

FIG. 45 illustrates an embodiment configured to treat a relativelypermeable formation without substantially pyrolyzing mobilized fluids.Low temperature heat source 2216 may be disposed in production well2210. Low temperature heat source 2216, conduit 2212 and impermeablelayers 2204 may be configured as described in the embodiment shown inFIG. 44. Low temperature heat source 2216 may be further configured toprovide heat to formation 2200 to heat some or all of formation 2200 toan average temperature within the mobilization temperature range.Mobilized fluids within formation 2200 may flow towards a bottom offormation 2200 substantially by gravity. Pressurizing fluid 2214 may beprovided into formation 2200 through conduit 2212 and may be configured,as described in the embodiment shown in FIG. 44, to increase a flow ofthe mobilized fluids towards the bottom of formation 2200. Pressurizingfluid 2214 may also be provided into formation 2200 through a conduitdisposed in/or proximate to production well 2210. Formation fluids maybe removed through production well 2210 at and/or near the bottom offormation 2200. Low temperature heat source 2216 may provide heat to theformation fluids removed through production well 2210. The provided heatmay vaporize the removed formation fluids within production well 2210such that the formation fluids may be removed as a vapor. The providedheat may also increase an API gravity of the removed formation fluidswithin production well 2210.

FIG. 46 illustrates an embodiment for treating a relatively permeableformation with layers 2201 of heavy hydrocarbons separated byimpermeable layers 2204. Heat injection well 2220 and production well2210 may be disposed in relatively permeable formation 2200.Substantially impermeable layers 2204 may separate layers 2201. Heavyhydrocarbons may be disposed in layers 2201. Low temperature heat source2216 may be disposed in injection well 2220. Low temperature heat source2216 may be configured as described in any of the above embodiments.Heavy hydrocarbons may be mobilized by heat provided from lowtemperature heat source 2216 such that a viscosity of the heavyhydrocarbons may be substantially reduced. Pressurizing fluid 2214 maybe provided through openings in injection well 2220 into layers 2201.The pressure of pressurizing fluid 2214 may cause the mobilized fluidsto flow towards production well 2210. The pressure of pressurizing fluid2214 at or near injection well 2220 may be about 7 bars absolute toabout 70 bars absolute. However, the pressure of pressurizing fluid 2214may be controlled to remain below a pressure that may lift theoverburden of relatively permeable formation 2200.

High temperature heat source 2218 may be disposed in production well2210. High temperature heat source 2218 may be configured as describedin any of the above embodiments. Heat provided by high temperature heatsource 2218 may substantially pyrolyze a portion of the mobilized fluidswithin a selected pyrolyzation section proximate to production well2210. The pyrolyzation and/or mobilized fluids may be removed fromlayers 2201 by production well 2210. High temperature heat source 2218may further upgrade the removed formation fluids within production well2210. The removed formation fluids may be removed as a vapor throughproduction well 2210. A pressure at or near production well 2210 may beless than about 70 bars absolute. By not heating the entire formation topyrolyzation temperatures, the process may produce a substantiallyhigher ratio of energy produced versus energy input for the in situconversion process. Upgrading of the formation fluids at or nearproduction well 2210 may produce a substantially higher value product.

In another embodiment, high temperature heat source 2218 may be replacedwith low temperature heat source 2216 within production well 2210. Lowtemperature heat source 2216 may provide for substantially lesspyrolyzation of the heavy hydrocarbons within layers 2201 than hightemperature heat source 2218. Therefore, the formation fluids removedthrough production well 2210 may not be as substantially upgraded asformation fluids removed through production well 2210 with hightemperature heat source 2218, as described for the embodiment shown inFIG. 46.

In another embodiment, pyrolyzation of the heavy hydrocarbons may beincreased by replacing low temperature heat source 2216 with hightemperature heat source 2218 within injection well 2220. Hightemperature heat source 2218 may provide for substantially morepyrolyzation of the heavy hydrocarbons within layers 2201 than lowtemperature heat source 2216. The formation fluids removed throughproduction well 2210 may be substantially upgraded as compared to theformation fluids removed in a process using low temperature heat source2216 within injection well 2220 as described in the embodiment shown inFIG. 46.

In some embodiments, a relatively permeable formation containing heavyhydrocarbons may be substantially below a substantially thickimpermeable layer (overburden). The overburden may have a thickness ofat least about 300 m or more. The thickness of the overburden may bedetermined by a geographical location of the relatively permeableformation.

In some embodiments, it may be more economical to provide heat to theformation with heat sources disposed horizontally within the relativelypermeable formation. A production well may also be disposed horizontallywithin the relatively permeable formation. The production well may bedisposed, however, either horizontally within the relatively permeableformation, vertically within the relatively permeable formation, or atan angle to the relatively permeable formation.

Production well 2210 may also be further configured as described in anyof the embodiments herein. For example, production well 2210 may includea valve configured to alter, maintain, and/or control a pressure of atleast a portion of the formation.

FIG. 47 illustrates an embodiment for treating a relatively permeableformation using horizontal heat sources. Heat source 2300 may bedisposed within relatively permeable formation 2200. Relativelypermeable formation 2200 may be substantially below impermeable layer2204. Impermeable layer 2204 may include, but may not be limited to,shale or carbonate. Impermeable layer 2204 may have a thickness of about20 m or more. As in FIG. 46, a thickness of impermeable layer 2204 maydepend on, for example, a geographic location of impermeable layer 2204.Heat source 2300 may be disposed horizontally within relativelypermeable formation 2200. Heat source 2300 may be configured to provideheat to a portion of relatively permeable formation 2200. Heat source2300 may include a low temperature heat source and/or a high temperatureheat source as described in any of the above embodiments. The providedheat may be configured to substantially mobilize a portion of heavyhydrocarbons within relatively permeable formation 2200 as in any of theembodiments described herein. The provided heat may also be configuredto pyrolyze a portion of heavy hydrocarbons within relatively permeableformation 2200 as in any of the embodiments described herein. A lengthof heat source 2300 disposed within relatively permeable formation 2200may be between about 50 m to about 1500 m. The length of heat source2300 within relatively permeable formation 2200 may vary, however,depending on, for example, a width of relatively permeable formation2200, a desired production rate, and an energy output of heat source2300.

FIG. 48 illustrates an embodiment for treating a relatively permeableformation using substantially horizontal heat sources. Heat sources 2300may be disposed horizontally within relatively permeable formation 2200.Heat sources 2300 may be configured as described in the above embodimentshown in FIG. 47. Heat sources 2300 are depicted in FIG. 48 from adifferent perspective than the heat sources shown in FIG. 47. Relativelypermeable formation 2200 may be substantially below impermeable layer2204. Production well 2302 may be disposed vertically, horizontally, orat an angle to relatively permeable formation 2200. The location ofproduction well 2302 within relatively permeable formation 2200 may varydepending on, for example, a desired product and a desired productionrate. For example, production well 2302 may be disposed proximate to abottom of relatively permeable formation 2200.

Heat sources 2300 may provide heat to substantially mobilize a portionof the heavy hydrocarbons within relatively permeable formation 2200.The mobilized fluids may flow towards a bottom of relatively permeableformation 2200 substantially by gravity. The mobilized fluids may beremoved through production well 2302. Each of heat sources 2300 disposedat or near the bottom of relatively permeable formation 2200 may beconfigured to heat some or all of a section proximate the bottom offormation 2200 to a temperature sufficient to pyrolyze heavyhydrocarbons within the section. Such a section may be referred to as aselected pyrolyzation section. A temperature within the selectedpyrolyzation section may be between about 270° C. and about 400° C. andmay be configured as described in any of the embodiments herein.Pyrolysis of the heavy hydrocarbons within the selected pyrolyzationsection may convert at least a portion of the heavy hydrocarbons intopyrolyzation fluids. The pyrolyzation fluids may be removed throughproduction well 2302. Production well 2302 may be disposed within theselected pyrolyzation section. In some embodiments, one or more of heatsources 2300 may be turned down and/or off after substantiallymobilizing the majority of the heavy hydrocarbons within relativelypermeable formation 2200. Doing so may more efficiently heat theformation and/or may save on input energy costs associated with the insitu process. Also, heating during “off peak” times may be cheaper.

In an embodiment, production well 2302 may remain closed until atemperature sufficient to pyrolyze at least a portion of the heavyhydrocarbons in the selected pyrolyzation section may be reached. Doingso may inhibit production of substantial amounts of unfavorable heavyhydrocarbons from relatively permeable formation 2200. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

In addition, heat may be provided within production well 2302 tovaporize the removed formation fluids. Heat may also be provided withinproduction well 2302 to pyrolyze and/or upgrade the removed formationfluids as described in any of the embodiments herein.

A pressurizing fluid may be provided into relatively permeable formation2200 through heat sources 2300. The pressurizing fluid may increase theflow of the mobilized fluids towards production well 2302. For example,increasing the pressure of the pressurizing fluid proximate heat sources2300 will tend to increase the flow of the mobilized fluids towardsproduction well 2302. The pressurizing fluid may include, but may not belimited to, N₂, CO₂, CH₄, H₂, steam, and/or mixtures thereof.Alternatively, the pressurizing fluid may be provided through aninjection well disposed in relatively permeable formation 2200.

In addition, pressure in relatively permeable formation 2200 may becontrolled such that a production rate of formation fluids may becontrolled. The pressure in relatively permeable formation 2200 may becontrolled through, for example, production well 2302, heat sources2300, and/or a pressure control well disposed in relatively permeableformation 2200.

Production well 2302 may also be further configured as described in anyof the embodiments herein. For example, production well 2302 may includea valve configured to alter, maintain, and/or control a pressure of atleast a portion of the formation.

In an embodiment, an in situ process for treating a relatively permeableformation may include providing heat to a portion of a formation from aplurality of heat sources. A plurality of heat sources may be arrangedwithin a relatively permeable formation in a pattern. FIG. 49illustrates an embodiment of pattern 2404 of heat sources 2400 andproduction well 2402 that may be configured to treat a relativelypermeable formation. Heat sources 2400 may be arranged in a “5 spot”pattern with production well 2402. In the “5 spot” pattern, four heatsources 2400 may be arranged substantially equidistant from productionwell 2402 and substantially equidistant from each other as depicted inFIG. 49. Depending on, for example, the heat generated by each heatsource 2400, a spacing between heat sources 2400 and production well2402 may be determined by a desired product or a desired productionrate. Heat sources 2400 may also be configured as a production well. Aspacing between heat sources 2400 and production well 2402 may be, forexample, about 15 m. Also, production well 2402 may be configured as aheat source.

FIG. 50 illustrates an alternate embodiment of pattern 2406 of heatsources 2400 that may be arranged in a “7 spot” pattern with productionwell 2402. In the “7 spot” pattern, six heat sources 2400 may bearranged substantially equidistant from production well 2402 andsubstantially equidistant from each other as depicted in FIG. 50. Heatsources 2400 may also be configured as a production well. Also,production well 2402 may be configured as a heat source. A spacingbetween heat sources 2400 and production well 2402 may be determined asdescribed in any of the above embodiments.

It is to be understood a geometrical pattern of heat sources 2400 andproduction wells 2402 is described herein by example. A pattern of heatsources 2400 and production wells 2402 may vary depending on, forexample, the type of relatively permeable formation configured to betreated. For example, a pattern of heat sources 2400 and productionwells 2402 may include a pattern as described in any of the embodimentsherein. In addition, a location of a production well 2402 within apattern of heat sources 2400 may be determined by, for example, adesired heating rate of the relatively permeable formation, a heatingrate of the heat sources, a type of heat source, a type of relativelypermeable formation, a composition of the relatively permeableformation, a viscosity of the relatively permeable formation, and/or adesired production rate.

In some embodiments, a portion of a relatively permeable formation maybe heated at a heating rate in a range from about 0.1° C./day to about50° C./day. A majority of hydrocarbons may be produced from a formationat a heating rate within a range of about 0.1° C./day to about 15°C./day. In an embodiment, the relatively permeable formation may beheated at a rate of less than about 0.7° C./day through a significantportion of a temperature range in which pyrolyzation fluids are removedfrom the formation. The significant portion may be greater than 50% ofthe time needed to span the temperature range, more than 75% of the timeneeded to span the temperature range, or more than 90% of the timeneeded to span the temperature range.

A quality of produced hydrocarbon fluids from a relatively permeableformation may also be described by a carbon number distribution. Ingeneral, lower carbon number products such as products having carbonnumbers less than about 25 may be considered to be more valuable thanproducts having carbon numbers greater than about 25. In an embodiment,treating a relatively permeable formation may include providing heat toat least a portion of a formation to produce hydrocarbon fluids from theformation of which a majority of the produced fluid may have carbonnumbers of less than approximately 25, or, for example, less thanapproximately 20. For example, less than about 20% by weight of theproduced condensable fluid may have carbon numbers greater than about20.

In an embodiment, a pressure may be increased within a portion of arelatively permeable formation to a desired pressure during mobilizationand/or pyrolysis of the heavy hydrocarbons. A desired pressure may bewithin a range from about 2 bars absolute to about 70 bars absolute. Amajority of hydrocarbon fluids, however, may be produced whilemaintaining the pressure within a range from about 7 bars absolute toabout 30 bars absolute. The pressure during mobilization and/orpyrolysis may vary or be varied. The pressure may be varied to control acomposition of the produced fluid, to control a percentage ofcondensable fluid as compared to non-condensable fluid, or to control anAPI gravity of fluid being produced. Increasing pressure may increasethe API gravity of the produced fluid. Increasing pressure may alsoincrease a percentage of paraffins within the produced fluid.

Increasing the reservoir pressure may increase a hydrogen partialpressure within the produced fluid. For example, a hydrogen partialpressure within the produced fluid may be increased autogenously orthrough hydrogen injection. The increased hydrogen partial pressure mayupgrade the heavy hydrocarbons. The heavy hydrocarbons may be reduced tolighter, higher quality hydrocarbons. The lighter hydrocarbons may beproduced by reaction of hydrogen with heavy hydrocarbon fragments withinthe produced fluid. The hydrogen dissolved in the fluid may also reduceolefins within the produced fluid. Therefore, an increased hydrogenpressure in the fluid may decrease a percentage of olefins within theproduced fluid. Decreasing the percentage of olefins and/or heavyhydrocarbons within the produced fluid may increase a quality (e.g., anAPI gravity) of the produced fluid. In some embodiments, a pressurewithin a portion of a relatively permeable formation may be raised bygas generation within the heated portion.

In an embodiment, a fluid produced from a portion of a relativelypermeable formation by an in situ process, as described in any of theembodiments herein, may include nitrogen. For example, less than about0.5% by weight of the condensable fluid may include nitrogen or, forexample, less than about 0.1% by weight of the condensable fluid. Inaddition, a fluid produced by an in situ process as described in aboveembodiments may include oxygen. For example, less than about 7% byweight of the condensable fluid may include oxygen or, for example, lessthan about 5% by weight of the condensable fluid. A fluid produced froma relatively permeable formation may also include sulfur. For example,less than about 5% by weight of the condensable fluid may include sulfuror, for example, less than about 3% by weight of the condensable fluid.In some embodiments, a weight percent of nitrogen, oxygen, and/or sulfurin a condensable fluid may be decreased by increasing a fluid pressurein a relatively permeable formation during an in situ process.

In an embodiment, condensable hydrocarbons of a fluid produced from arelatively permeable formation may include aromatic compounds. Forexample, greater than about 20% by weight of the condensablehydrocarbons may include aromatic compounds. In another embodiment, anaromatic compound weight percent may include greater than about 30% ofthe condensable hydrocarbons. The condensable hydrocarbons may alsoinclude di-aromatic compounds. For example, less than about 20% byweight of the condensable hydrocarbons may include di-aromaticcompounds. In another embodiment, di-aromatic compounds may include lessthan about 15% by weight of the condensable hydrocarbons. Thecondensable hydrocarbons may also include tri-aromatic compounds. Forexample, less than about 4% by weight of the condensable hydrocarbonsmay include tri-aromatic compounds. In another embodiment, less thanabout 1% by weight of the condensable hydrocarbons may includetri-aromatic compounds.

In an embodiment, an in situ process for treating heavy hydrocarbons inat least a portion of a relatively low permeability formation mayinclude heating the formation from one or more heat sources. The one ormore heat sources may be configured as described in any of theembodiments herein. At least one of the heat sources may be anelectrical heater. In one embodiment, at least one of the heat sourcesmay be located in a heater well. The heater well may include a conduitthrough which a hot fluid flows that transfers heat to the formation. Atleast some of the heavy hydrocarbons in a selected section of theformation may be pyrolyzed by the heat from the one or more heatsources. A temperature sufficient to pyrolyze heavy hydrocarbons in ahydrocarbon containing formation of relatively low permeability may bewithin a range from about 270° C. to about 300° C. In other embodiments,a temperature sufficient to pyrolyze heavy hydrocarbons may be within arange from about 300° C. to about 375° C. Pyrolyzation fluids may beproduced from the formation. In one embodiment, fluids may be producedthrough at least one production well.

In addition, heating may also increase the average permeability of atleast a portion of the selected section. The increase in temperature ofthe formation may create thermal fractures in the formation. The thermalfractures may propagate between heat sources, further increasing thepermeability in a portion of a selected section of the formation. Due tothe increased permeability, mobilized fluids in the formation may tendto flow to a heat source and may be pyrolyzed.

In one embodiment, the pressure in at least a portion of the relativelylow permeability formation may be controlled to maintain a compositionof produced formation fluids within a desired range. The composition ofthe produced formation fluids may be monitored. The pressure may becontrolled by a back pressure valve located proximate to where theformation fluids are produced. A desired operating pressure of aproduction well, such that a desired composition may be obtained, may bedetermined from experimental data for the relationship between pressureand the composition of pyrolysis products of the heavy hydrocarbons inthe formation.

FIG. 51 is a view of an embodiment of a heat source and production wellpattern for heating heavy hydrocarbons in a relatively low permeabilityformation. Heat sources 2502, 2503, and 2504 may be arranged in atriangular pattern with the heat sources at the apices of the triangulargrid. A production well 2500 may be located proximate to the center ofthe triangular grid. In other embodiments, production well 2500 may beplaced at any location on the grid pattern. Heat sources may be arrangedin patterns other than the triangular pattern shown in FIG. 51. Forexample, wells may be arranged in square patterns. Heat sources 2502,2503, and 2504 may heat the formation to a temperature at which at leastsome of the heavy hydrocarbons in the formation can pyrolyze.Pyrolyzation fluids may tend to flow toward the production well, asindicated by the arrows, and formation fluids may be produced throughproduction well 2500.

In one embodiment, an average distance between heat sources effective topyrolyze heavy hydrocarbons in the formation may be between about 5 mand about 8 m. In one embodiment, a more effective range may be betweenabout 2 m and about 5 m.

One embodiment for treating heavy hydrocarbons in a portion of arelatively low permeability formation may include providing heat fromone or more heat sources to pyrolyze some of the heavy hydrocarbons andvaporize a portion of the heavy hydrocarbons in a selected section ofthe formation. Heavy hydrocarbons in the formation may be vaporized at atemperature between about 300° C. and about 350° C. In anotherembodiment, heavy hydrocarbons in the formation may be vaporized at atemperature between about 350° C. and about 450° C. The vaporized andpyrolyzed fluids may flow to a location proximate to where the fluidsare produced. In one embodiment, fluids may be produced from theformation through a production well. Due to a buildup of pressure fromvaporization, it may be necessary to relieve the pressure through theproduction well.

FIG. 51 may also represent an embodiment in which at least some heavyhydrocarbons may be pyrolyzed and a portion of the heavy hydrocarbonsmay be vaporized at or near at least two heat sources. Heat sources2502, 2503, and 2504 may heat the formation to a temperature sufficientto vaporize fluid in the formation. The vaporized fluid may tend to flowin a direction from the heat sources toward production well 2500, asindicated by the arrows, where the fluid may be produced.

In one embodiment for treating heavy hydrocarbons in a portion of ahydrocarbon containing formation of relatively low permeability, heatmay be provided from one or more heat sources with at least one of theheat sources located in a heater well. The heat sources may pyrolyze atleast some heavy hydrocarbons in a selected section of the formation andmay pressurize at least a portion of the selected section. Duringheating, the pressure within the formation may increase substantially.The pressure in the formation may be controlled such that the pressurein the formation may be maintained to produce a fluid of a desiredcomposition. Pyrolysis products may be removed from the formation asvapor from one or more heater wells disposed in the formation. Backpressure created by heating the formation may be used to produce thepyrolysis products through the one or more heater wells.

FIG. 52 is a view of an embodiment of a heat source pattern for heatingheavy hydrocarbons in a portion of a hydrocarbon containing formation ofrelatively low permeability and producing fluids from one or more heaterwells. Heat sources 2502 may be arranged in a triangular pattern and maybe disposed in heater wells. The heat sources may provide heat topyrolyze some or all of the fluid in the formation. Fluids may beproduced through one or more of the heater wells.

One embodiment for treating heavy hydrocarbons in a portion of ahydrocarbon containing formation of relatively low permeability mayinclude heating the formation to create at least two zones within theformation such that the at least two zones have different averagetemperatures. One or more heat sources may heat a selected first sectionof the formation that creates a pyrolysis zone in which heavyhydrocarbons may be pyrolyzed within the selected first section. Inaddition, one or more heat sources may heat a selected second section ofthe formation such that at least some of the heavy hydrocarbons in thesecond selected section have an average temperature less than theaverage temperature of the pyrolysis zone.

Heating the selected second section may decrease the viscosity of someof the heavy hydrocarbon in the selected second section to create a lowviscosity zone. The decrease in viscosity of the heavy hydrocarbons inthe selected second section may be sufficient to produce mobilizedfluids within the selected second section. The mobilized fluids may flowinto the pyrolysis zone. For example, increasing the temperature of theheavy hydrocarbons in the formation to between about 200° C. and about250° C. may decrease the viscosity of the heavy hydrocarbonssufficiently for the heavy hydrocarbons to flow through the formation.In another embodiment, increasing the temperature of the fluid tobetween about 180° C. and about 200° C. may also be sufficient tomobilize the heavy hydrocarbons. For example, the viscosity of heavyhydrocarbons in a formation at 200° C. may be about 50 centipoise toabout 200 centipoise.

Heating may create thermal fractures that may propagate between heatsources in both the selected first section and the selected secondsection. The thermal fractures may substantially increase thepermeability of the formation and may facilitate the flow of mobilizedfluids from the low viscosity zone to the pyrolysis zone. In oneembodiment, a vertical hydraulic fracture may be created in theformation to further increase permeability. The presence of a hydraulicfracture may also be desirable since heavy hydrocarbons that may collectin the hydraulic fracture may have an increased residence time in thepyrolysis zone. The increased residence time may result in increasedpyrolysis of the heavy hydrocarbons in the pyrolysis zone.

Also, substantially simultaneously with the decrease in viscosity, thepressure in the low viscosity zone may increase due to thermal expansionof the formation and evaporation of entrained water in the formation toform steam. For example, pressures in the low viscosity zone may rangefrom about 10 bars absolute to an overburden pressure, which may beabout 70 bars absolute. In other embodiments the pressure may range fromabout 15 bars absolute to about 50 bars absolute. The value of thepressure may depend upon factors such as, but not limited to, the degreeof thermal fracturing, the amount of water in the formation, andmaterial properties of the formation. The pressure in the pyrolysis zonemay be substantially lower than the pressure in the low viscosity zonebecause of the higher permeability of the pyrolysis zone. The highertemperature in the pyrolysis zone compared to the low viscosity zone maycause a higher degree of thermal fracturing, and thus a greaterpermeability. For example, pyrolysis zone pressures may range from about3.5 bars absolute to about 10 bars absolute. In other embodiments,pyrolysis zone pressures may range from about 10 bars absolute to about15 bars absolute.

The pressure differential between the pyrolysis zone and the lowviscosity zone may force some mobilized fluids to flow from the lowviscosity zone into the pyrolysis zone. Heavy hydrocarbons in thepyrolysis zone may be upgraded by pyrolysis into pyrolyzation fluids.Pyrolyzation fluids may be produced from the formation through aproduction well. In another embodiment, a pyrolyzation fluid producedfrom the formation may include a liquid.

In one embodiment, the density of the heat sources in the pyrolysis zonemay be greater than the density of heat sources in the low viscosityzone. The increased density of heat sources in the pyrolysis zone mayestablish and maintain a uniform pyrolysis temperature in the pyrolysiszone. Using a lower density of heat sources in the low viscosity zonemay be more efficient and economical due to the lower temperaturerequired in the low viscosity zone. In one embodiment, an averagedistance between heat sources for heating the first selected section maybe between about 5 m and about 10 m. Alternatively, an average distancemay be between about 2 m and about 5 m. In some embodiments, an averagedistance between heat sources for heating the second selected sectionmay be between about 5 m and about 20 m.

In an embodiment, the pyrolysis zone and one or more low viscosity zonesmay be heated sequentially over time. Heat sources may heat the firstselected section until an average temperature of the pyrolysis zonereaches a desired pyrolysis temperature. Subsequently, heat sources mayheat one or more low viscosity zones of the selected second section thatmay be nearest the pyrolysis zone until such low viscosity zones reach adesired average temperature. Heating low viscosity zones of the selectedsecond section farther away from the pyrolysis zone may continue in alike manner.

In one embodiment, heat may be provided to a formation to create aplanar pyrolysis zone and a planar low viscosity zone. One or moreplanar low viscosity zones may be created with symmetry about thepyrolysis zone and may tend to force heavy hydrocarbons toward thepyrolysis zone. In one embodiment, fluids in the pyrolysis zone may beproduced from a production well located in the pyrolysis zone.

FIG. 53 is a view of an embodiment of a heat source and production wellpattern illustrating a pyrolysis zone and a low viscosity zone. Heatsources 2512 along plane 2504 and plane 2506 may heat planar region 2508to create a pyrolysis zone. Heating may create thermal fractures 2510 inthe pyrolysis zone. Heating with heat sources 2514 in planes 2516, 2518,2520, and 2522 may create a low viscosity zone.with an increasedpermeability due to thermal fractures. Pressure differential between thelow viscosity zone and the pyrolysis zone may force mobilized fluid fromthe low viscosity zone into the pyrolysis zone. The permeability createdby thermal fractures 2510 may be sufficiently high to create asubstantially uniform pyrolysis zone. Pyrolyzation fluids may beproduced through production well 2500.

In one embodiment, it may be desirable to create the pyrolysis zone andlow viscosity zone sequentially over time. The heat sources nearest thepyrolysis zone may be activated first, for example, heat sources 2512 inplane 2504 and plane 2506 of FIG.53. A substantially uniform temperaturemay be established in the pyrolysis zone after a period of time.Mobilized fluids that flow through the pyrolysis zone may undergopyrolysis and vaporize. Once the pyrolysis zone is established, heatsources in the low viscosity zone (e.g., heat sources 2514 in plane 2516and plane 2520) nearest the pyrolysis zone may be turned on and/or up toestablish a low viscosity zone. A larger low viscosity zone may bedeveloped by repeatedly activating heat sources (e.g., heat sources 2514in plane 2518 and plane 2522) farther away from the pyrolysis zone.

FIG. 54 is an expanded view of the pattern shown in FIG. 53. The fourplanar vertical regions 2540 that correspond to region 2508 in FIG. 53,may include heat sources that may create pyrolysis zones. Regions 2548,2550, and 2552 may include heat sources that apply heat to create a lowviscosity zone. Production wells 2500 may be disposed in regions wherepyrolysis occurs and may be configured to remove the pyrolyzationfluids. In one embodiment, a length of the pyrolysis zones 2540 may bebetween about 75 m and about 100 m. In another embodiment, a length ofthe pyrolysis zones may be between about 100 m and about 125 m. Inanother embodiment, an average distance between production wells in thesame plane may be between about 100 m and about 150 m. In oneembodiment, a distance between plane 2542 and plane 2544 may be betweenabout 40 m and about 80 m. In some embodiments, more than one productionwell may be disposed in a region where pyrolysis occurs. Plane 2542 andplane 2544 may be substantially parallel. The formation may includeadditional planar vertical pyrolysis zones that may be substantiallyparallel to each other. Hot fluids may be provided into vertical planarregions such that in situ pyrolysis of heavy hydrocarbons may occur.Pyrolyzation fluids may be removed by production wells disposed in thevertical planar regions.

An embodiment of a planar pyrolysis zone may include a verticalhydraulic fracture created by a production well in the formation. Theformation may include heat sources located substantially parallel to thevertical hydraulic fracture in the formation. Heat sources in a planarregion adjacent to the fracture may provide heat sufficient to pyrolyzeat least some or all of the heavy hydrocarbons in a pyrolysis zone. Heatsources outside the planar region may heat the formation to atemperature sufficient to decrease the viscosity of the fluids in a lowviscosity zone.

FIG. 55 is a view of an embodiment for treating heavy hydrocarbons in atleast a portion of a hydrocarbon containing formation of relatively lowpermeability that may include a well pattern and a vertical hydraulicfracture. Production well 2600 may be configured to create fracture 2602by methods described in any of the embodiments herein. The width offracture 2602 generated by hydraulic fracturing may be between about 0.3cm and about 1 cm. In other embodiments, the width of fracture 2602 maybe between about 1 cm and about 3 cm. The pyrolysis zone may be formedin a planar region on either side of the vertical hydraulic fracture byheating the planar region to an average temperature within a pyrolysistemperature range with heat sources 2604 in plane 2605 and plane 2606.Creation of a low viscosity zone on both sides of the pyrolysis zone,above plane 2605 and below plane 2606, may be accomplished by heatsources outside the pyrolysis zone. For example, heat sources 2608 inplanes 2610, 2612, 2614, and 2616 may heat the low viscosity zone to atemperature sufficient to lower the viscosity of heavy hydrocarbons inthe formation. Mobilized fluids in the low viscosity zone may flow tothe pyrolysis zone due to the pressure differential between the lowviscosity zone and the pyrolysis zone and the increased permeabilityfrom thermal fractures.

FIG. 56 is an expanded view of an embodiment shown in FIG. 55. FIG. 56illustrates a formation with two fractures 2645 a and 2645 b along plane2645 and two fractures 2646 a and 2646 b along plane 2646. Each fracturemay be produced using production wells 2640. Plane 2645 and plane 2646may be substantially parallel. The length of a fracture created byhydraulic fracturing in relatively low permeability formations may bebetween about 75 m and about 100 m. In some embodiments, the verticalhydraulic fracture may be between about 100 m and about 125 m. Verticalhydraulic fractures may propagate substantially equal distances along aplane from a production well. Therefore, since it may be undesirable forfractures along the same plane to join, the distance between productionwells along the same plane may be between about 100 m and about 150 m.As the distance between fractures on different planes increases, forexample the distance between plane 2645 and plane 2646, the flow ofmobilized fluids farthest from either fracture may decrease. A distancebetween fractures on different planes that may be economical andeffective for the transport of mobilized fluids to the pyrolysis zonemay be about 40 m to about 80 m.

Plane 2648 and plane 2649 may include heat sources that may provide heatsufficient to create a pyrolysis zone between plane 2648 and plane 2649.Plane 2651 and plane 2652 may include heat sources that create apyrolysis zone between plane 2651 and plane 2652. Heat sources inregions 2650, 2660, 2655, and 2656 may provide heat that may create lowviscosity zones. Mobilized fluids in regions 2650, 2660, 2655, and 2656may tend to flow in a direction toward the closest fracture in theformation. Mobilized fluids entering the pyrolysis zone may bepyrolyzed. Pyrolyzation fluids may be produced from production wells2640.

In one embodiment, heat may be provided to a relatively low permeabilityformation to create a radial pyrolysis zone and a low viscosity zone. Aradial heating region may be created that tends to force fluids toward apyrolysis zone. Fluids may be pyrolyzed in the pyrolysis zone.Pyrolyzation fluids may be produced from production wells disposed inthe pyrolysis zone. Heat sources may be located around a production wellin concentric rings such as regular polygons. A variety ofconfigurations of heat sources may be possible. Heat sources in a ringnearest the production well may heat the fluid to a pyrolysistemperature to create a radial pyrolysis zone. Additional concentricrings of heat sources may radiate outward from the pyrolysis zone andmay heat the fluid to create a low viscosity zone. Mobilized fluid inthe low viscosity zone may flow to the pyrolysis zone due to thepressure differential between the low viscosity zone and the pyrolysiszone, and from the increased permeability due to thermal fracturing.Pyrolyzation fluids may be produced from the formation through theproduction well.

Several patterns of heat sources arranged in rings around productionwells may be utilized to create a radial pyrolysis region in hydrocarboncontaining formations. Various patterns shown in FIGS. 57-70 aredescribed herein. Although such patterns are discussed in the context ofheavy hydrocarbons, it is to be understood that any of the patternsshown in FIGS. 57-70 may be used for other hydrocarbon containingformations (e.g., for coal, oil shale, etc.).

FIG. 57 illustrates an embodiment of a pattern of heat sources 2705 thatmay create a radial pyrolysis zone surrounded by a low viscosity zone.Production well 2701 may be surrounded by concentric rings 2702, 2703,and 2704 of heat sources 2705. Heat sources 2705 in ring 2702 may heatthe formation to create radial pyrolysis zone 2710. Heat sources 2705 inrings 2703 and 2704 outside pyrolysis zone 2710 may heat the formationto create a low viscosity zone. Mobilized fluids may flow radiallyinward from the low viscosity zone to the pyrolysis zone 2710. Fluidsmay be produced through production well 2701. In one embodiment, anaverage distance between heat sources may be between about 2 m and about10 m. Alternatively, the average distance may be between about 10 m andabout 20 m.

As in other embodiments, it may be desirable to create pyrolysis zonesand low viscosity zones sequentially. Heat sources 2705 nearestproduction well 2701 may be activated first, for example, heat sources2705 in ring 2702. A substantially uniform temperature pyrolysis zonemay be established after a, period of time. Fluids that flow through thepyrolysis zone may undergo pyrolysis and vaporization. Once thepyrolysis zone is established, heat sources 2705 in the low viscosityzone substantially near the pyrolysis zone (e.g., heat sources 2705 inring 2703) may be activated to provide heat to a portion of a lowviscosity zone. Fluid may flow inward towards production well 2701 dueto a pressure differential between the low viscosity zone and thepyrolysis zone, as indicated by the arrows. A larger low viscosity zonemay be developed by repeatedly activating heat sources farther away fromthe fracture, for example, heat sources 2705 in ring 2704.

Several patterns of heat sources and production wells may be utilized inembodiments of radial heating zones for treating a relatively lowpermeability formation. The heat sources may be arranged in rings aroundthe production wells. The pattern around each production well may be ahexagon that may contain a number of heat sources.

In FIG. 58, production well 2701 and heat source 2712 may be located atthe apices of a triangular grid. The triangular grid may be anequilateral triangular grid with sides of length, s. Production wells2701 may be spaced at a distance of about 1.732(s). Production well 2701may be disposed at a center of a hexagonal pattern with one ring 2713 ofsix heat sources 2712. Each heat source 2712 may provide substantiallyequal amounts of heat to three production wells. Therefore, each ring2713 of six heat sources 2712 may contribute approximately twoequivalent heat sources per production well 2701.

FIG. 59 illustrates a pattern of production wells 2701 with an innerhexagonal ring 2713 and an outer hexagonal ring 2715 of heat sources2712. In this pattern, production wells 2701 may be spaced at a distanceof about 2(1.732)s. Heat sources 2712 may be located at all other gridpositions. This pattern may result in a ratio of equivalent heat sourcesto production wells that may approach eleven.

FIG. 60 illustrates three rings of heat sources 2712 surroundingproduction well 2701. Production well 2701 may be surrounded by ring2713 of six heat sources 2712. Second hexagonally shaped ring 2716 oftwelve heat sources 2712 may surround ring 2713. Third ring 2718 of heatsources 2712 may include twelve heat sources that may providesubstantially equal amounts of heat to two production wells and six heatsources that may provide substantially equal amounts of heat to threeproduction wells. Therefore, a total of eight equivalent heat sourcesmay be disposed on third ring 2718. Production well 2701 may be providedheat from an equivalent of about twenty-six heat sources. FIG. 61illustrates an even larger pattern that may have a greater spacingbetween production wells 2701.

Alternatively, square patterns may be provided with production wellsplaced, for example, in the center of each third square, resulting innine heat sources for each production well. Production wells may beplaced within each fifth square in a square pattern, which may result intwenty-five heat sources for each production well.

FIGS. 62, 63, 64, and 65 illustrate alternate embodiments in which bothproduction wells and heat sources may be located at the apices of atriangular grid. In FIG. 62, a triangular grid, with a spacing of s, mayhave production wells 2701 spaced at a distance of 2s. A hexagonalpattern may include one ring 2730 of six heat sources 2732. Each heatsource 2732 may provide substantially equal amounts of heat to twoproduction wells 2701. Therefore, each ring 2730 of six heat sources2732 contributes approximately three equivalent heat sources perproduction well 2701.

FIG. 63 illustrates a pattern of production wells 2701 with innerhexagonal ring 2734 and outer hexagonal ring 2736. Production wells 2701may be spaced at a distance of 3s. Heat sources 2732 may be located atapices of hexagonal ring 2734 and hexagonal ring 2736. Hexagonal ring2734 and hexagonal ring 2736 may include six heat sources each. Thepattern in FIG. 63 may result in a ratio of heat sources 2732 toproduction well 2701 of eight.

FIG. 64 illustrates a pattern of production wells 2701 also with twohexagonal rings of heat sources surrounding each production well.Production well 2701 may be surrounded by ring 2738 of six heat sources2732. Production wells 2701 may be spaced at a distance of 4s. Secondhexagonally shaped ring 2740 may surround ring 2738. Second hexagonallyshaped ring 2740 may include twelve heat sources 2732. This pattern mayresult in a ratio of heat sources 2732 to production wells 2701 that mayapproach fifteen.

FIG. 65 illustrates a pattern of heat sources 2732 with three rings ofheat sources 2732 surrounding each production well 2701. Productionwells 2701 may be surrounded by ring 2742 of six heat sources 2732.Second ring 2744 of twelve heat sources 2732 may surround ring 2742.Third ring 2746 of heat sources 2732 may surround second ring 2744.Third ring 2746 may include 6 equivalent heat sources. This pattern mayresult in a ratio of heat sources 2732 to production wells 2701 that isabout 24:1.

FIGS. 66, 67, 68, and 69 illustrate patterns in which the productionwell may be disposed at a center of a triangular grid such that theproduction well may be equidistant from the apices of the triangulargrid. In FIG. 66, the triangular grid of heater wells with a spacing ofs may include production wells 2760 spaced at a distance of s. Eachproduction well 2760 may be surrounded by ring 2764 of three heatsources 2762. Each heat source 2762 may provide substantially equalamounts of heat to three production wells 2760. Therefore, each ring2764 of three heat sources 2762 may contribute one equivalent heatsource per production well 2760.

FIG. 67 illustrates a pattern of production wells 2760 with innertriangular ring 2766 and outer hexagonal ring 2768. In this pattern,production wells 2760 may be spaced at a distance of 2s. Heat sources2762 may be located at apices of inner ring 2766 and outer ring 2768.Inner triangular ring 2766 may contribute three equivalent heat sourcesper production well 2760. Outer hexagonal ring 2768 containing threeheater wells may contribute one equivalent heat source per productionwell 2760. Thus, a total of four equivalent heat sources may provideheat to production well 2760.

FIG. 68 illustrates a pattern of production wells with one innertriangular ring of heat sources surrounding each production well and oneirregular hexagonal outer ring. Production wells 2760 may be surroundedby ring 2770 of three heat sources 2762. Production wells 2760 may bespaced at a distance of 3s. Irregular hexagonally shaped ring 2772 ofnine heat sources 2762 may surround ring 2770. This pattern may resultin a ratio of heat sources 2762 to production wells 2760 of nine.

FIG. 69 illustrates triangular patterns of heat sources with three ringsof heat sources surrounding each production well. Production wells 2760may be surrounded by ring 2774 of three heat sources 2762. Irregularhexagon pattern 2776 of nine heat sources 2762 may surround ring 2774.Third set 2778 of heat sources 2762 may surround hexagonal pattern 2776.Third set 2778 may contribute four equivalent heat sources to productionwell 2760. A ratio of equivalent heat sources to production well 2760may be sixteen.

One embodiment for treating heavy hydrocarbons in at least a portion ofa relatively low permeability formation may include heating theformation from three or more heat sources. At least three of the heatsources may be arranged in a substantially triangular pattern. At leastsome of the heavy hydrocarbons in a selected section of the formationmay be pyrolyzed by the heat from the three or more heat sources.Pyrolyzation fluids generated by pyrolysis of heavy hydrocarbons in theformation may be produced from the formation. In one embodiment, fluidsmay be produced through at least one production well disposed in theformation.

FIG. 70 depicts an embodiment of a pattern of heat sources 2705 arrangedin a triangular pattern. Production well 2701 may be surrounded bytriangles 2780, 2782, and 2784 of heat sources 2705. Heat sources 2705in triangles 2780, 2782, and 2784 may provide heat to the formation. Theprovided heat may raise an average temperature of the formation to apyrolysis temperature. Pyrolyzation fluids may flow to production well2701. Formation fluids may be produced in production well 2701.

FIG. 71 illustrates a schematic diagram of an embodiment of surfacefacilities 2800 that may be configured to treat a formation fluid. Theformation fluid may be produced though a production well as describedherein. The formation fluid may include any of a formation fluidproduced by any of the methods as described herein. As shown in FIG. 71,surface facilities 2800 may be coupled to well head 2802. Well head 2802may also be coupled to a production well formed in a formation. Forexample, the well head may be coupled to a production well by variousmechanical devices proximate an upper surface of the formation.Therefore, a formation fluid produced through a production well may alsoflow through well head 2802. Well head 2802 may be configured toseparate the formation fluid into gas stream 2804, liquid hydrocarboncondensate stream 2806, and water stream 2808.

Surface facilities 2800 may be configured such that water stream 2808may flow from well head 2802 to a portion of a formation, to acontainment system, or to a processing unit. For example, water stream2808 may flow from well head 2802 to an ammonia production unit. Thesurface facilities may be configured such that ammonia produced in theammonia production unit may flow to an ammonium sulfate unit. Theammonium sulfate unit may be configured to combine the ammonia withH₂SO₄ or SO₂/SO₃ to produce ammonium sulfate. In addition, the surfacefacilities may be configured such that ammonia produced in the ammoniaproduction unit may flow to a urea production unit. The urea productionunit may be configured to combine carbon dioxide with the ammonia toproduce urea.

Surface facilities 2800 may be configured such that gas stream 2804 mayflow through a conduit from well head 2802 to gas treatment unit 2810.The conduit may include a pipe or any other fluid communicationmechanism known in the art. The gas treatment unit may be configured toseparate various components of gas stream 2804. For example, the gastreatment unit may be configured to separate gas stream 2804 into carbondioxide stream 2812, hydrogen sulfide stream 2814, hydrogen stream 2816,and stream 2818 that may include, but may not be limited to, methane,ethane, propane, butanes (including n-butane or iso-butane), pentane,ethene, propene, butene, pentene, water or combinations thereof.

Surface facilities 2800 may be configured such that the carbon dioxidestream may flow through a conduit to a formation, to a containmentsystem, to a disposal unit, and/or to another processing unit. Inaddition, the facilities may be configured such that the hydrogensulfide stream may also flow through a conduit to a containment systemand/or to another processing unit. For example, the hydrogen sulfidestream may be converted into elemental sulfur in a Claus process unit.The gas treatment unit may also be configured to separate gas stream2804 into stream 2819 that may include heavier hydrocarbon componentsfrom gas stream 2804. Heavier hydrocarbon components may include, forexample, hydrocarbons having a carbon number of greater than about 5.Surface facilities 2800 may be configured such that heavier hydrocarboncomponents in stream 2819 may be provided to liquid hydrocarboncondensate stream 2806.

Surface facilities 2800 may also include processing unit 2821.Processing unit 2821 may be configured to separate stream 2818 into anumber of streams. Each of the number of streams may be rich in apredetermined component or a predetermined number of compounds. Forexample, processing unit 2821 may separate stream 2818 into firstportion 2820 of stream 2818, second portion 2823 of stream 2818, thirdportion 2825 of stream 2818, and fourth portion 2831 of stream 2818.First portion 2820 of stream 2818 may include lighter hydrocarboncomponents such as methane and ethane. The surface facilities may beconfigured such that first portion 2820 of stream 2818 may flow from gastreatment unit 2810 to power generation unit 2822.

Power generation unit 2822 may be configured for extracting useableenergy from the first portion of stream 2818. For example, stream 2818may be produced under pressure. In this manner, power generation unit2822 may include a turbine configured to generate electricity from thefirst portion of stream 2818. The power generation unit may alsoinclude, for example, a molten carbonate fuel cell, a solid oxide fuelcell, or other type of fuel cell. The facilities may be furtherconfigured such that the extracted useable energy may be provided touser 2824. User 2824 may include, for example, surface facilities 2800,a heat source disposed within a formation, and/or a consumer of useableenergy.

Second portion 2823 of stream 2818 may also include light hydrocarboncomponents. For example, second portion 2823 of stream 2818 may include,but may not be limited to, methane and ethane. Surface facilities 2800may also be configured such that second portion 2823 of stream 2818 maybe provided to natural gas grid 2827. Alternatively, surface facilitiesmay also be configured such that second portion 2823 of stream 2818 maybe provided to a local market. The local market may include a consumermarket or a commercial market. In this manner, the second portion 2823of stream 2818 may be used as an end product or an intermediate productdepending on, for example, a composition of the light hydrocarboncomponents.

Third portion 2825 of stream 2818 may include liquefied petroleum gas(“LPG”). Major constituents of LPG may include hydrocarbon containingthree or four carbon atoms such as propane and butane. Butane mayinclude n-butane or iso-butane. LPG may also include relatively smallconcentrations of other hydrocarbons such as ethene, propene, butene,and pentene. Depending on the source of LPG and how it has beenproduced, however. LPG may also include additional components. LPG maybe a gas at atmospheric pressure and normal ambient temperatures. LPGmay be liquefied, however, when moderate pressure is applied or when thetemperature is sufficiently reduced. When such moderate pressure isreleased, LPG gas may have about 250 times a volume of LPG liquid.Therefore, large amounts of energy may be stored and transportedcompactly as LPG.

Surface facilities 2800 may also be configured such that third portion2825 of stream 2818 may be provided to local market 2829. The localmarket may include a consumer market or a commercial market. In thismanner, the third portion 2825 of stream 2818 may be used as an endproduct or an intermediate product depending on, for example, acomposition of the LPG. For example, LPG may be used in applications,such as food processing, aerosol propellants, and automotive fuel. LPGmay usually be available in one or two forms for standard heating andcooking purposes: commercial propane and commercial butane. Propane maybe more versatile for general use than butane because, for example,propane has a lower boiling point than butane.

Surface facilities 2800 may also be configured such that fourth portion2831 of stream 2818 may flow from the gas treatment unit to hydrogenmanufacturing unit 2828. Hydrogen containing stream 2830 is shownexiting hydrogen manufacturing unit 2828. Examples of hydrogenmanufacturing unit 2828 may include a steam reformer and a catalyticflameless distributed combustor with a hydrogen separation membrane.FIG. 72 illustrates an embodiment of a catalytic flameless distributedcombustor. An example of a catalytic flameless distributed combustorwith a hydrogen separation membrane is illustrated in U.S. patentapplication Ser. No. 60/273,354, filed on Mar. 5, 2001, which isincorporated by reference as if fully set forth herein. A catalyticflameless distributed combustor may include fuel line 2850, oxidant line2852, catalyst 2854, and membrane 2856. Fourth portion 2831 of stream2818 may be provided to hydrogen manufacturing unit 2828 as fuel 2858.Fuel 2858 within fuel line 2850 may mix within reaction zone in annularspace 2859 between the fuel line and the oxidant line. Reaction of thefuel with the oxidant in the presence of catalyst 2854 may producereaction products that include H₂. Membrane 2856 may allow a portion ofthe generated H₂ to pass into annular space 2860 between outer wall 2862of oxidant line 2852 and membrane 2856. Excess fuel passing out of fuelline 2850 may be circulated back to entrance of hydrogen manufacturingunit 2828. Combustion products leaving oxidant line 2852 may includecarbon dioxide and other reactions products as well as some fuel andoxidant. The fuel and oxidant may be separated and recirculated back tothe hydrogen manufacturing unit. Carbon dioxide may be separated fromthe exit stream. The carbon dioxide may be sequestered within a portionof a formation or used for an alternate purpose.

Fuel line 2850 may be concentrically positioned within oxidant line2852. Critical flow orifices within fuel line 2850 may be configured toallow fuel to enter into a reaction zone in annular space 2859 betweenthe fuel line and oxidant line 2852. The fuel line may carry a mixtureof water and vaporized hydrocarbons such as, but not limited to,methane, ethane, propane, butane, methanol, ethanol, or combinationsthereof. The oxidant line may carry an oxidant such as, but not limitedto, air, oxygen enriched air, oxygen, hydrogen peroxide, or combinationsthereof.

Catalyst 2854 may be located in the reaction zone to allow reactionsthat produce H₂ to proceed at relatively low temperatures. Without acatalyst and without membrane separation of H₂, a steam reformationreaction may need to be conducted in a series of reactors withtemperatures for a shift reaction occurring in excess of 980° C. With acatalyst and with separation of H₂ from the reaction stream, thereaction may occur at temperatures within a range from about 300° C. toabout 600° C., or within a range from about 400° C. to about 500° C.Catalyst 2854 may be any steam reforming catalyst. In selectedembodiments, catalyst 2854 is a group VIII transition metal, such asnickel. The catalyst may be supported on porous substrate 2864. Thesubstrate may include group III or group IV elements, such as, but notlimited to, aluminum, silicon, titanium, or zirconium. In an embodiment,the substrate is alumina (Al₂O₃).

Membrane 2856 may remove H₂ from a reaction stream within a reactionzone of a hydrogen manufacturing unit 2828. When H₂ is removed from thereaction stream, reactions within the reaction zone may generateadditional H₂. A vacuum may draw H₂ from an annular region betweenmembrane 2856 and wall 2862 of oxidant line 2852. Alternately, H₂ may beremoved from the annular region in a carrier gas. Membrane 2856 mayseparate H₂ from other components within the reaction stream. The othercomponents may include, but are not limited to, reaction products, fuel,water, and hydrogen sulfide. The membrane may be a hydrogen-permeableand hydrogen selective material such as, but not limited to, a ceramic,carbon, metal, or combination thereof. The membrane may include, but isnot limited to, metals of group VIII, V, III, or I such as palladium,platinum, nickel, silver, tantalum, vanadium, yttrium, and/or niobium.The membrane may be supported on a porous substrate such as alumina. Thesupport may separate the membrane 2856 from catalyst 2854. Theseparation distance and insulation properties of the support may help tomaintain the membrane within a desired temperature range. In thismanner, hydrogen manufacturing unit 2828 may be configured to producehydrogen-rich stream 2830 from the second portion stream 2818. Thesurface facilities may also be configured such that hydrogen-rich stream2830 may flow into hydrogen stream 2816 to form stream 2832. In thismanner, stream 2832 may include a larger volume of hydrogen than eitherhydrogen-rich stream 2830 or hydrogen stream 2816.

Surface facilities 2800 may be configured such that hydrocarboncondensate stream 2806 may flow through a conduit from well head 2802 tohydrotreating unit 2834. Hydrotreating unit 2834 may be configured tohydrogenate hydrocarbon condensate stream 2806 to form hydrogenatedhydrocarbon condensate stream 2836. The hydrotreater may be configuredto upgrade and swell the hydrocarbon condensate. For example, surfacefacilities 2800 may also be configured to provide stream 2832 (whichincludes a relatively high concentration of hydrogen) to hydrotreatingunit 2834. In this manner, H₂ in stream 2832 may hydrogenate a doublebond of the hydrocarbon condensate, thereby reducing a potential forpolymerization of the hydrocarbon condensate. In addition, hydrogen mayalso neutralize radicals in the hydrocarbon condensate. In this manner,the hydrogenated hydrocarbon condensate may include relatively shortchain hydrocarbon fluids. Furthermore, hydrotreating unit 2834 may beconfigured to reduce sulfur, nitrogen, and aromatic hydrocarbons inhydrocarbon condensate stream 2806. Hydrotreating unit 2834 may be adeep hydrotreating unit or a mild hydrotreating unit. An appropriatehydrotreating unit may vary depending on, for example, a composition ofstream 2832, a composition of the hydrocarbon condensate stream, and/ora selected composition of the hydrogenated hydrocarbon condensatestream.

Surface facilities 2800 may be configured such that hydrogenatedhydrocarbon condensate stream 2836 may flow from hydrotreating unit 2834to transportation unit 2838. Transportation unit 2838 may be configuredto collect a volume of the hydrogenated hydrocarbon condensate and/or totransport the hydrogenated hydrocarbon condensate to market center 2840.For example, market center 2840 may include, but may not be limited to,a consumer marketplace or a commercial marketplace. A commercialmarketplace may include, but may not be limited to, a refinery. In thismanner, the hydrogenated hydrocarbon condensate may be used as an endproduct or an intermediate product depending on, for example, acomposition of the hydrogenated hydrocarbon condensate.

Alternatively, surface facilities 2800 may be configured such thathydrogenated hydrocarbon condensate stream 2836 may flow to a splitteror an ethene production unit. The splitter may be configured to separatethe hydrogenated hydrocarbon condensate stream into a hydrocarbon streamincluding components having carbon numbers of 5 or 6, a naphtha stream,a kerosene stream, and a diesel stream. Streams exiting the splitter maybe fed to the ethene production unit. In addition, the hydrocarboncondensate stream and the hydrogenated hydrocarbon condensate stream maybe fed to the ethene production unit. Ethene produced by the etheneproduction unit may be fed to a petrochemical complex to produce baseand industrial chemicals and polymers. Alternatively, the streamsexiting the splitter may be fed to a hydrogen conversion unit. A recyclestream may be configured to flow from the hydrogen conversion unit tothe splitter. The hydrocarbon stream exiting the splitter and thenaphtha stream may be fed to a mogas production unit. The kerosenestream and the diesel stream may be distributed as product.

FIG. 73 illustrates an embodiment of an additional processing unit thatmay be included in surface facilities 2800 such as the facilitiesdepicted in FIG. 71. Air 2903 may be fed to air separation unit 2900.Air separation unit 2900 may be configured to generate nitrogen streamBy, 2902 and oxygen stream 2905. Oxygen stream 2905 and steam 2904 maybe injected into exhausted coal resource 2906 to generate synthesis gas2907. Produced synthesis gas 2907 may be provided to Shell MiddleDistillates process unit 2910 that may be configured to produce middledistillates 2912. In addition, produced synthesis gas 2907 may beprovided to catalytic methanation process unit 2914 that may beconfigured to produce natural gas 2916. Produced synthesis gas 2907 mayalso be provided to methanol production unit 2918 to produce methanol2920. Furthermore, produced synthesis gas 2907 may be provided toprocess unit 2922 for production of ammonia and/or urea 2924, and fuelcell 2926 that may be configured to produce electricity 2928. Synthesisgas 2907 may also be routed to power generation unit 2930, such as aturbine or combustor, to produce electricity 2932.

FIG. 74 illustrates an example of a square pattern of heat sources 3000and production wells 3002. Heat sources 3000 are disposed at vertices ofsquares 3010. Production well 3002 is placed in a center of every thirdsquare in both x- and y-directions. Midlines 3006 are formed equidistantto two production wells 3002, and perpendicular to a line connectingsuch production wells. Intersections of midlines 3006 at vertices 3008form unit cell 3012. Heat source 3000 b and heat source 3000 c are onlypartially within unit cell 3012. Only the one-half fraction of heatsource 3000 b and the one-quarter fraction of heat source 3000 c withinunit cell 3012 are configured to provide heat within unit cell 3012. Thefraction of heat source 3000 outside of unit cell 3012 is configured toprovide heat outside of unit cell 3012. The number of heat sources 3000within one unit cell 3012 is a ratio of heat sources 3000 per productionwell 3002 within the formation.

The total number of heat sources inside unit cell 3012 is determined bythe following method:

(a) 4 heat sources 3000 a inside unit cell 3012 are counted as one heatsource each;

(b) 8 heat sources 3000 b on midlines 3006 are counted as one-half heatsource each; and

(c) 4 heat sources 3000 c at vertices 3008 are counted as one-quarterheat source each.

The total number of heat sources is determined from adding the heatsources counted by, (a) 4, (b) 8/2=4, and (c) 4/4=1, for a total numberof 9 heat sources 3000 in unit cell 3012. Therefore, a ratio of heatsources 3000 to production wells 3002 is determined as 9:1 for thepattern illustrated in FIG. 74.

FIG. 75 illustrates an example of another pattern of heat sources 3000and production wells 3002. Midlines 3006 are formed equidistant from thetwo production wells 3002, and perpendicular to a line connecting suchproduction wells. Unit cell 3014 is determined by intersection ofmidlines 3006 at vertices 3008. Twelve heat sources 3000 are counted inunit cell 3014 by a method as described in the above embodiments, ofwhich six are whole sources of heat, and six are one third sources ofheat (with the other two thirds of heat from such six wells going toother patterns). Thus, a ratio of heat sources 3000 to production wells3002 is determined as 8:1 for the pattern illustrated in FIG. 75. Anexample of a pattern of heat sources is illustrated in U.S. Pat. No.2,923,535 issued to Ljungstrom, which is incorporated by reference as iffully set forth herein.

In certain embodiments, a triangular pattern of heat sources may provideadvantages when compared to alternative patterns of heat sources, suchas squares, hexagons, and hexagons with additional heaters installedhalfway between the hexagon comers (12 to 1 pattern). Squares, hexagons,and the 12:1 patterns are disclosed in U.S. Pat. No. 2,923,535 and/or inU.S. Pat. No. 4,886,118. For example, a triangular pattern of heatsources may provide more uniform heating of a hydrocarbon containingformation resulting from a more uniform temperature distribution of anarea of a formation heated by the pattern of heat sources.

FIG. 76 illustrates an embodiment of triangular pattern 3100 of heatsources 3102. FIG. 76a illustrates an embodiment of square pattern 3101of heat sources 3103. FIG. 77 illustrates an embodiment of hexagonalpattern 3104 of heat sources 3106. FIG. 77a illustrates an embodiment of12 to 1 pattern 3105 of heat sources 3107. A temperature distributionfor all patterns may be determined by an analytical method. Theanalytical method may be simplified by analyzing only temperature fieldswithin “confined” patterns (e.g., hexagons), i.e., completely surroundedby others. In addition, the temperature field may be estimated to be asuperposition of analytical solutions corresponding to a single heatsource.

The comparisons of patterns of heat sources were evaluated for the sameheater well to density and the same heating input regime. For example, anumber of heat sources per unit area in a triangular pattern is the sameas the number of heat sources per unit area in the 10 m hexagonalpattern if the space between heat sources is increased to about 12.2 min the triangular pattern. The equivalent spacing for a square patternwould be 11.3 m, while the equivalent spacing for a 12 to 1 patternwould be 15.7 m.

FIG. 78 illustrates temperature profile 3110 after three years ofheating for a triangular pattern with a 12.2 m spacing in a typicalGreen River oil shale. The triangular pattern may be configured as shownin FIG. 76. Temperature profile 3110 is a three-dimensional plot oftemperature versus a location within a triangular pattern. FIG. 79illustrates temperature profile 3108 after three years of heating for asquare pattern with 11.3 m spacing in a typical Green River oil shale.Temperature profile 3108 is a three-dimensional plot of temperatureversus a location within a square pattern. The square pattern may beconfigured as shown in FIG. 76a. FIG. 79a illustrates temperatureprofile 3109 after three years of heating for a hexagonal pattern with10.0 m spacing in a typical Green River oil shale. Temperature profile3109 is a three-dimensional plot of temperature versus a location withina hexagonal pattern. The hexagonal pattern may be configured as shown inFIG. 77.

As shown in a comparison of FIGS. 78, 79 and 79 a, a temperature profileof the triangular pattern is more uniform than a temperature profile ofthe square or hexagonal pattern. For example, a minimum temperature ofthe square pattern is approximately 280° C., and a minimum temperatureof the hexagonal pattern is approximately 250° C. In contrast, a minimumtemperature of the triangular pattern is approximately 300° C.Therefore, a temperature variation within the triangular pattern after 3years of heating is 20° C. less than a temperature variation within thesquare pattern and 50° C. less than a temperature variation within thehexagonal pattern. For a chemical process, where reaction rate isproportional to an exponent of temperature, even a 20° C. difference issubstantial.

FIG. 80 illustrates a comparison plot between the average patterntemperature (in degrees Celsius) and temperatures at the coldest spotsfor each pattern, as a function of time (in years). The coldest spot foreach pattern is located at a pattern center (centroid). As shown in FIG.76, the coldest spot of a triangular pattern is point 3118, while point3117 is the coldest spot of a square pattern, as shown in FIG. 76a. Asshown in FIG. 77, the coldest spot of a hexagonal pattern is point 3114,while point 3115 is the coldest spot of a 12 to 1 pattern, as shown inFIG. 77a. The difference between an average pattern temperature andtemperature of the coldest spot represents how uniform the temperaturedistribution for a given pattern is. The more uniform the heating, thebetter the product quality that may be made. The larger the volumefraction of resource that is overheated, the more undesirable productcomposition will be made.

As shown in FIG. 80, the difference between an average temperature 3120of a pattern and temperature of the coldest spot is less for thetriangular pattern 3118 than for square pattern 3117, hexagonal pattern3114, or 12 to 1 pattern 3115. Again, there is a substantial differencebetween triangular and hexagonal patterns.

Another way to assess the uniformity of temperature distribution is tocompare temperatures of the coldest spot of a pattern with a pointlocated at the center of a side of a pattern midway between heaters. Asshown in FIG. 77, point 3112 is located at the center of a side of thehexagonal pattern midway between heaters. As shown in FIG. 76, point3116 is located at the center of a side of a triangular pattern midwaybetween heaters. Point 3119 is located at the center of a side of thesquare pattern midway between heaters, as shown in FIG. 76a.

FIG. 81 illustrates a comparison plot between the average patterntemperature 3120 (in degrees Celsius), temperatures at coldest spot 3118for triangular patterns, coldest spot 3114 for hexagonal patterns, point3116 located at the center of a side of triangular pattern midwaybetween heaters, and point 3112 located at the center of a side ofhexagonal pattern midway between heaters, as a function of time (inyears). FIG. 81a illustrates a comparison plot between the averagepattern temperature 3120 (in degrees Celsius), temperatures at coldestspot 3117 and point 3119 located at the center of a side of a patternmidway between heaters, as a function of time (in years), for a squarepattern.

As shown in a comparison of FIGS. 81 and 81a, for each pattern, atemperature at a center of a side midway between heaters is higher thana temperature at a center of the pattern. A difference between atemperature at a center of a side midway between heaters and a center ofthe hexagonal pattern increases substantially during the first year ofheating, and stays relatively constant afterward. A difference between atemperature at an outer lateral boundary and a center of the triangularpattern, however, is negligible. Therefore, a temperature distributionin a triangular pattern is substantially more uniform than a temperaturedistribution in a hexagonal pattern. A square pattern also provides moreuniform temperature distribution than a hexagonal pattern, however it isstill less uniform than a temperature distribution in a triangularpattern.

A triangular pattern of heat sources may have, for example, a shortertotal process time than a square, hexagonal or 12 to 1 pattern of heatsources for the same heater well density. A total process time mayinclude a time required for an average temperature of a heated portionof a formation to reach a target temperature and a time required for atemperature at a coldest spot within the heated portion to reach thetarget temperature. For example, heat may be provided to the portion ofthe formation until an average temperature of the heated portion reachesthe target temperature. After the average temperature of the heatedportion reaches the target temperature, an energy supply to the heatsources may be reduced such that less or minimal heat may be provided tothe heated portion. An example of a target temperature may beapproximately 340° C. The target temperature, however, may varydepending on, for example, formation composition and/or formationconditions such as pressure.

FIG. 81b illustrates a comparison plot between the average patterntemperature and temperatures at the coldest spots for each pattern, as afunction of time when heaters are turned off after the averagetemperature reaches a target value. As shown in FIG. 81b, an averagetemperature 3120 of the formation reaches a target temperature (about340° C.) in approximately 3 years. As shown in FIG. 81b, a temperatureat the. coldest point within the triangular pattern 3118 reaches thetarget temperature (about 340° C.) about 0.8 years later. In thismanner, a total process time for such a triangular pattern is about 3.8years when the heat input is discontinued when the target averagetemperature is reached. As shown in FIG. 81b, a temperature at thecoldest point within the triangular pattern reaches the targettemperature (about 340° C.) before a temperature at the coldest pointwithin the square pattern 3117 or a temperature at the coldest pointwithin the hexagonal pattern 3114 reaches the target temperature. Atemperature at the coldest point within the hexagonal pattern, however,reaches the target temperature after an additional time of about 2 yearswhen the heaters are turned off upon reaching the target averagetemperature. Therefore, a total process time for a hexagonal pattern isabout 5.0 years. In this manner, a total process time for heating aportion of a formation with a triangular pattern is 1.2 years less(approximately 25%) than a total process time for heating a portion of aformation with a hexagonal pattern. In a preferred mode, the power tothe heaters may be reduced or turned off when the average temperature ofthe pattern reaches a target level. This prevents overheating theresource, which wastes energy and produces lower product quality. Thetriangular pattern has the most uniform temperatures and the leastoverheating. Although a capital cost of such a triangular pattern may beapproximately the same as a capital cost of the hexagonal pattern, thetriangular pattern may accelerate oil production and requires a shortertotal process time. In this manner, such a triangular pattern may bemore economical than a hexagonal pattern.

A spacing of heat sources in a triangular pattern, which may yield thesame process time as a hexagonal pattern having about a 10.0 m spacebetween heat sources, may be equal to approximately 14.3 m. In thismanner, the total process time of a triangular pattern may be achievedby using about 26% less heat sources than may be included in a hexagonalpattern. In this manner, such a triangular pattern may havesubstantially lower capital and operating costs. As such, thistriangular pattern may also be more economical than a hexagonal pattern.

FIG. 12 depicts an embodiment of a natural distributed combustor. In oneexperiment the embodiment schematically shown in FIG. 12 was used toheat high volatile bituminous C coal in situ. A heating well wasconfigured to be heated with electrical resistance heaters and/or anatural distributed combustor such as is schematically shown in FIG. 12.Thermocouples were located every 2 feet along the length of the naturaldistributed combustor (along conduit 532 as is schematically shown inFIG. 12). The coal was first heated with electrical resistance heatersuntil pyrolysis was complete proximate the well. FIG. 130 depicts squaredata points measured during electrical resistance heating at variousdepths in the coal after the temperature profile had stabilized (thecoal seam was about 16 feet thick starting at about 28 feet of depth).At this point heat energy was being supplied at about 300 Watts perfoot. Air was subsequently injected via conduit 532 at graduallyincreasing rates, and electric power was substantially simultaneouslydecreased. Combustion products were removed from the reaction zone in anannulus surrounding conduit 532 and the electrical resistance heater.The electric power was decreased at rates that would approximatelyoffset heating provided by the combustion of the coal caused by thenatural distributed combustor. Air rates were increased, and power rateswere decreased, over a period of about 2 hours until no electric powerwas being supplied. FIG. 130 depicts diamond data points measured duringnatural distributed combustion heating (without any electricalresistance heating) at various depths in the coal after the temperatureprofile had stabilized. As can be seen in FIG. 130, the naturaldistributed combustion heating provided a temperature profile that iscomparable to the electrical resistance temperature profile. Thisexperiment demonstrated that natural distributed combustors can provideformation heating that is comparable to the formation heating providedby electrical resistance heaters. This experiment was repeated atdifferent temperatures, and in two other wells, all with similarresults.

Numerical calculations have been made for a natural distributedcombustor system configured to heat a hydrocarbon containing formation.A commercially available program called PRO-II was used to make examplecalculations based on a conduit of diameter 6.03 cm with a wallthickness of 0.39 cm. The conduit was disposed in an opening in theformation with a diameter of 14.4 cm. The conduit had critical floworifices of 1.27 mm diameter spaced 183 cm apart. The conduit wasconfigured to heat a formation of 91.4 meters thick. A flow rate of airwas 1.70 standard cubic meters per minute through the critical floworifices. A pressure of air at the inlet of the conduit was 7 barsabsolute. Exhaust gases had a pressure of 3.3 bars absolute. A heatingoutput of 1066 watts per meter was used. A temperature in the openingwas set at 760° C. The calculations determined a minimal pressure dropwithin the conduit of about 0.023 bar. The pressure drop within theopening was less than 0.0013 bar.

FIG. 82 illustrates extension (in meters) of a reaction zone within acoal formation over time (in years) according to the parameters set inthe calculations. The width of the reaction zone increases with time asthe carbon was oxidized proximate to the center.

Numerical calculations have been made for heat transfer using aconductor-in-conduit heater. Calculations were made for a conductorhaving a diameter of about 1 inch (2.54 cm) disposed in a conduit havinga diameter of about 3 inches (7.62 cm). The conductor-in-conduit heaterwas disposed in an opening of a carbon containing formation having adiameter of about 6 inches (15.24 cm). An emissivity of the carboncontaining formation was maintained at a value of 0.9, which is expectedfor geological materials. The conductor and the conduit were givenalternate emissivity values of high emissivity (0.86), which is commonfor oxidized metal surfaces, and low emissivity (0.1), which is forpolished and/or un-oxidized metal surfaces. The conduit was filled witheither air or helium. Helium is known to be a more thermally conductivegas than air. The space between the conduit and the opening was filledwith a gas mixture of methane, carbon dioxide, and hydrogen gases. Twodifferent gas mixtures were used. The first gas mixture had molefractions of 0.5 for methane, 0.3 for carbon dioxide, and 0.2 forhydrogen. The second gas mixture had mole fractions of 0.2 for methane,0.2 for carbon dioxide, and 0.6 for hydrogen.

FIG. 83 illustrates a calculated ratio of conductive heat transfer toradiative heat transfer versus a temperature of a face of thehydrocarbon containing formation in the opening for an air filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values, thermal conductivities,dimensions of the conductor, conduit, and opening, and the temperatureof the conduit. Line 3204 is calculated for the low emissivity value(0.1). Line 3206 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit provides for a higherratio of conductive to radiative heat transfer to the formation. Thedecrease in the ratio with an increase in temperature may be due to areduction of conductive heat transfer with increasing temperature. Asthe temperature on the face of the formation increases, a temperaturedifference between the face and the heater is reduced, thus reducing atemperature gradient that drives conductive heat transfer.

FIG. 84 illustrates a calculated ratio of conductive heat transfer toradiative heat transfer versus a temperature at a face of thehydrocarbon containing formation in the opening for a helium filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values; thermal conductivities;dimensions of the conductor, conduit, and opening; and the temperatureof the conduit. Line 3208 is calculated for the low emissivity value(0.1). Line 3210 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit again provides for ahigher ratio of conductive to radiative heat transfer to the formation.The use of helium instead of air in the conduit significantly increasesthe ratio of conductive heat transfer to radiative heat transfer. Thismay be due to a thermal conductivity of helium being about 5.2 to about5.3 times greater than a thermal conductivity of air.

FIG. 85 illustrates temperatures of the conductor, the conduit, and theopening versus a temperature at a face of the hydrocarbon containingformation for a helium filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of thehydrocarbon containing formation. Conductor temperature 3212 and conduittemperature 3214 were calculated from opening temperature 3216 using thedimensions of the conductor, conduit, and opening, values ofemissivities for the conductor, conduit, and face, and thermalconductivities for gases (helium, methane, carbon dioxide, andhydrogen). It may be seen from the plots of temperatures of theconductor, conduit, and opening for the conduit filled with helium, thatat higher temperatures approaching 871° C., the temperatures of theconductor, conduit, and opening begin to substantially equilibrate.

FIG. 86 illustrates temperatures of the conductor, the conduit, and theopening versus a temperature at a face of the hydrocarbon containingformation for an air filled conduit and a high emissivity of 0.86. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of thehydrocarbon containing formation. Conductor temperature 3212 and conduittemperature 3214 were calculated from opening temperature 3216 using thedimensions of the conductor, conduit, and opening, values ofemissivities for the conductor, conduit, and face, and thermalconductivities for gases (air, methane, carbon dioxide, and hydrogen).It may be seen from the plots of temperatures of the conductor, conduit,and opening for the conduit filled with air, that at higher temperaturesapproaching 871° C., the temperatures of the conductor, conduit, andopening begin to substantially equilibrate, as seen for the heliumfilled conduit with high emissivity.

FIG. 87 illustrates temperatures of the conductor, the conduit, and theopening versus a temperature at a face of the hydrocarbon containingformation for a helium filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of thehydrocarbon containing formation. Conductor temperature 3212 and conduittemperature 3214 were calculated from opening temperature 3216 using thedimensions of the conductor, conduit, and opening, values ofemissivities for the conductor, conduit, and face, and thermalconductivities for gases (helium, methane, carbon dioxide, andhydrogen). It may be seen from the plots of temperatures of theconductor, conduit, and opening for the conduit filled with helium, thatat higher temperatures approaching 871° C., the temperatures of theconductor, conduit, and opening do not begin to substantiallyequilibrate as seen for the high emissivity example shown in FIG. 85.Also, higher temperatures in the conductor and the conduit are neededfor an opening and face temperature of 871° C. than as for the exampleshown in FIG. 85. Thus, increasing an emissivity of the conductor andthe conduit may be advantageous in reducing operating temperaturesneeded to produce a desired temperature in a hydrocarbon containingformation. Such reduced operating temperatures may allow for the use ofless expensive alloys for metallic conduits.

FIG. 88 illustrates temperatures of the conductor, the conduit, and theopening versus a temperature at a face of the hydrocarbon containingformation for an air filled conduit and a low emissivity of 0.1. Theopening has a gas mixture equivalent to the second mixture describedabove having a hydrogen mole fraction of 0.6. Opening temperature 3216was linearly increased from 93° C. to 871° C. Opening temperature 3216was assumed to be the same as the temperature at the face of thehydrocarbon containing formation. Conductor temperature 3212 and conduittemperature 3214 were calculated from opening temperature 3216 using thedimensions of the conductor, conduit, and opening, values ofemissivities for the conductor, conduit, and face, and thermalconductivities for gases (air, methane, carbon dioxide, and hydrogen).It may be seen from the plots of temperatures of the conductor, conduit,and opening for the conduit filled with helium, that at highertemperatures approaching 871° C., the temperatures of the conductor,conduit, and opening do not begin to substantially equilibrate as seenfor the high emissivity example shown in FIG. 86. Also, highertemperatures in the conductor and the conduit are needed for an openingand face temperature of 871° C. than as for the example shown in FIG.86. Thus, increasing an emissivity of the conductor and the conduit maybe advantageous in reducing operating temperatures needed to produce adesired temperature in a hydrocarbon containing formation. Such reducedoperating temperatures may provide for a lesser metallurgical costassociated with materials that require less substantial temperatureresistance (e.g., a lower melting point).

Calculations were also made using the first mixture of gas having ahydrogen mole fraction of 0.2. The calculations resulted insubstantially similar results to those for a hydrogen mole fraction of0.6.

FIG. 89 depicts a retort and collection system used to conduct certainexperiments. Retort vessel 3314 was a pressure vessel of 316 stainlesssteel configured to hold a material to be tested. The vessel andappropriate flow lines were wrapped with a 0.0254 meters by 1.83 meterselectric heating tape. The wrapping was configured to providesubstantially uniform heating throughout the retort system. Thetemperature was controlled by measuring a temperature of the retortvessel with a thermocouple and altering the temperature of the vesselwith a proportional controller. The heating tape was further wrappedwith insulation as shown. The vessel sat on a 0.0508 meters thickinsulating block heated only from the sides. The heating tape extendedpast the bottom of the stainless steel vessel to counteract heat lossfrom the bottom of the vessel.

A 0.00318 m stainless steel dip tube 3312 was inserted through meshscreen 3310 and into the small dimple on the bottom of vessel 3314. Diptube 3312 was slotted at the bottom so that solids could not plug thetube and prevent removal of the products. Screen 3310 was supportedalong the cylindrical wall of the vessel by a small ring having athickness of about 0.00159 m. Therefore, the small ring provides a spacebetween an end of dip tube 3312 and a bottom of vessel 3314 which alsoinhibited solids from plugging the dip tube. A thermocouple was attachedto the outside of the vessel to measure a temperature of the steelcylinder. The thermocouple was protected from direct heat of the heaterby a layer of insulation. An air-operated diaphragm-type backpressurevalve 3304 was provided for tests at elevated pressures. The products atatmospheric pressure pass into conventional glass laboratory condenser3320. Coolant disposed in the condenser 3320 was chilled water having atemperature of about 1.7° C. The oil vapor and steam products condensedin the flow lines of the condenser and flowed into the graduated glasscollection tube. A volume of produced oil and water was measuredvisually. Non-condensable gas flowed from condenser 3320 through gasbulb 3316. Gas bulb 3316 has a capacity of 500 cm³. In addition, gasbulb 3316 was originally filled with helium. The valves on the bulb weretwo-way valves 3317 to provide easy purging of bulb 3316 and removal ofnon-condensable gases for analysis. Considering a sweep efficiency ofthe bulb, the bulb would be expected to contain a composite sample ofthe previously produced 1 to 2 liters of gas. Standard gas analysismethods were used to determine the gas composition. The gas exiting thebulb passed into collection vessel 3318 that is in water 3322 in waterbath 3324. The water bath 3324 was graduated to provide an estimate ofthe volume of the produced gas over a time of the procedure (the waterlevel changed, thereby indicating the amount of gas produced). Thecollection vessel 3318 also included an inlet valve at a bottom of thecollection system under water and a septum at a top of the collectionsystem for transfer of gas samples to an analyzer.

At location 3300 one or more gases may be injected into the system shownin FIG. 89 to pressurize, maintain pressure, or sweep fluids in thesystem. Pressure gauge 3302 may be used to monitor pressure in thesystem. Heating/insulating material 3306 (e.g., insulation or atemperature control bath) may be used to regulate and/or maintaintemperatures. Controller 3308 may be used to control heating of vessel3314.

A final volume of gas produced is not the volume of gas collected overwater because carbon dioxide and hydrogen sulfide are soluble in water.Analysis of the water has shown that the gas collection system overwater removes about one-half of the carbon dioxide produced in a typicalexperiment. The concentration of carbon dioxide in water affects aconcentration of the non-soluble gases collected over water. Inaddition, the volume of gas collected over water was found to vary fromabout one-half to two-thirds of the volume of gas produced.

The system was purged with about 5 to 10 pore volumes of helium toremove all air and pressurized to about 20 bars absolute for 24 hours tocheck for pressure leaks. Heating was then started slowly, taking about4 days to reach 260° C. After about 8 to 12 hours at 260° C., thetemperature was raised as specified by the schedule desired for theparticular test. Readings of temperature on the inside and outside ofthe vessel were recorded frequently to assure that the controller wasworking correctly.

In one experiment oil shale was tested in the system shown in FIG. 89.In this experiment, 270° C. was about the lowest temperature at whichoil was generated at any appreciable rate. Thus, readings of oil canbegin at any time in this range. For water, production started at about100° C. and was monitored at all times during the run. For gas, variousamounts were generated during the course of production. Therefore,monitoring was needed throughout the run.

The oil and water production was collected in 4 or 5 fractionsthroughout the run. These fractions were composite samples over aparticular time interval involved. The cumulative volume of oil andwater in each fraction was measured as it accrued. After each fractionwas collected, the oil was analyzed as desired. The density of the oilwas measured.

After the test, the retort was cooled, opened, and inspected forevidence of any liquid residue. A representative sample of the crushedshale loaded into the retort was taken and analyzed for oil generatingpotential by the Fischer Assay method. After the test, three samples ofspent shale in the retort were taken: one near the top, one at themiddle, and one near the bottom. These were tested for remaining organicmatter and elemental analysis.

Experimental data from the experiment described above was used todetermine a pressure-temperature relationship relating to the quality ofthe produced fluids. Varying the operating conditions included alteringtemperatures and pressures. Various samples of oil shale were pyrolyzedat various operating conditions. The quality of the produced fluids wasdescribed by a number of desired properties. Desired properties includedAPI gravity, an ethene to ethane ratio, an atomic carbon to atomichydrogen ratio, equivalent liquids produced (gas and liquid), liquidsproduced, percent of Fischer Assay, and percent of fluids with carbonnumbers greater than about 25. Based on data collected these equilibriumexperiments, families of curves for several values of each of theproperties were constructed as shown in FIGS. 90-96. From these figures,the following relationships were used to describe the functionalrelationship of a given value of a property:

P=exp[(A/T)+B],

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄

A=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄

The generated curves may be used to determine a preferred temperatureand a preferred pressure that may produce fluids with desiredproperties. Data illustrating the pressure-temperature relationship of anumber of the desired properties for Green River oil shale was plottedin a number of the following figures.

In FIG. 90, a plot of gauge pressure versus temperature is depicted (inFIGS. 90-96 the pressure is indicated in bars). Lines representing thefraction of products with carbon numbers greater than about 25 wereplotted. For example, when operating at a temperature of 375° C. and apressure of 4.5 bars absolute, 15% of the produced fluid hydrocarbonshad a carbon number equal to or greater than 25. At low pyrolysistemperatures and high pressures, the fraction of produced fluids withcarbon numbers greater than about 25 decreases. Therefore, operating ata high pressure and a pyrolysis temperature at the lower end of thepyrolysis temperature zone tends to decrease the fraction of fluids withcarbon numbers greater than 25 produced from oil shale.

FIG. 91 illustrates oil quality produced from an oil shale formation asa function of pressure and temperature. Lines indicating different oilqualities, as defined by API gravity, are plotted. For example, thequality of the produced oil was 40° API when pressure was maintained atabout 11.1 bars absolute and a temperature was about 375° C. Asdescribed in above embodiments, low pyrolysis temperatures andrelatively high pressures may produce a high API gravity oil.

FIG. 92 illustrates an ethene to ethane ratio produced from an oil shaleformation as a function of pressure and temperature. For example, at apressure of 21.7 bars absolute and a temperature of 375° C., the ratioof ethene to ethane is approximately 0.01. The volume ratio of ethene toethane may predict an olefin to alkane ratio of hydrocarbons producedduring pyrolysis. To control olefin content, operating at lowerpyrolysis temperatures and a higher pressure may be beneficial. Olefincontent in above described embodiments may be reduced by operating atlow pyrolysis temperature and a high pressure.

FIG. 93 depicts the dependence of yield of equivalent liquids producedfrom an oil shale formation as a function of temperature and pressure.Line 3340 represents the pressure-temperature combination at which8.38×10⁻⁵ m³ of fluid per kilogram of oil shale (20 gallons/ton). Thepressure/temperature plot results in a line 3342 for the production oftotal fluids per ton of oil shale equal to 1.05×10⁻⁴ m³ /kg (25gallons/ton). Line 3344 illustrates that 1.21×10⁻⁴ m³ of fluid isproduced from 1 kilogram of oil shale (30 gallons/ton). For example, ata temperature of about 325° C. and a pressure of about 14.8 barsabsolute the resulting equivalent liquids was 8.38×10⁻⁵ m³ /kg. Astemperature of the retort increased and the pressure decreased the yieldof the equivalent liquids produced increased. Equivalent liquidsproduced was defined as the amount of liquid equivalent to the energyvalue of the produced gas and liquids.

FIG. 94 illustrates a plot of oil yield produced from treating an oilshale formation, measured as volume of liquids per ton of the formation,as a function of temperature and pressure of the retort. Temperature isillustrated in units of Celsius on the x-axis, and pressure isillustrated in units of bars absolute on the y-axis. As shown in FIG.94, the yield of liquid/condensable products increases as temperature ofthe retort increases and pressure of the retort decreases. The lines onFIG. 94 correspond to different liquid production rates measured as thevolume of liquids produced per weight of oil shale and are shown inTable 3.

TABLE 3 LINE VOLUME PRODUCED/MASS OF OIL SHALE (m³/kg) 3350 5.84 × 10⁻⁵3352 6.68 × 10⁻⁵ 3354 7.51 × 10⁻⁵ 3356 8.35 × 10⁻⁵

FIG. 95 illustrates yield of oil produced from treating an oil shaleformation expressed as a percent of Fischer assay as a function oftemperature and pressure. Temperature is illustrated in units of degreesCelsius on the x-axis, and gauge pressure is illustrated in units ofbars on the y-axis. Fischer assay was used as a method for assessing arecovery of hydrocarbon condensate from the oil shale. In this case, amaximum recovery would be 100% of the Fischer assay. As the temperaturedecreased and the pressure increased, the percent of Fischer assay yielddecreased.

FIG. 96 illustrates hydrogen to carbon ratio of hydrocarbon condensateproduced from an oil shale formation as a function of a temperature andpressure. Temperature is illustrated in units of degrees Celsius on thex-axis, and pressure is illustrated in units of bars on the y-axis. Asshown in FIG. 96, a hydrogen to carbon ratio of hydrocarbon condensateproduced from an oil shale formation decreases as a temperatureincreases and as a pressure decreases. As described in more detail withrespect to other embodiments herein, treating an oil shale formation athigh temperatures may decrease a hydrogen concentration of the producedhydrocarbon condensate.

FIG. 97 illustrates the effect of pressure and temperature within an oilshale formation on a ratio of olefins to paraffins. The relationship ofthe value of one of the properties (R) with temperature has the samefunctional form as the pressure-temperature relationships previouslydiscussed. In this case the property (R) can be explicitly expressed asa function of pressure and temperature.

R=exp[F(P)/T)+G(P)]

F(P)=ƒ₁*(P)^(3+ƒ) ₂*(P)^(2+ƒ) ₃*(P)+ƒ₄

G(P)=g ₁*(P)³ +g ₂*(P)² +g ₃*(P)+g ₄

wherein R is a value of the property, T is the absolute temperature (inKelvin), F(P) and G(P) are functions of pressure representing the slopeand intercept of a plot of R versus 1/T.

FIG. 97 is an example of such a plot for olefin to paraffin ratio. Datafrom the above experiments were compared to data from other sources.Isobars were plotted on a temperature versus olefin to paraffin ratiograph using data from a variety of sources. Data from the abovedescribed experiments included an isobar at 1 bar absolute 3360, 2.5bars absolute 3362, 4.5 bars absolute 3364, 7.9 bars absolute 3366, and14.8 bars absolute 3368. Additional data plotted included data from asurface retort, data from Ljungstrom 3361, and data from ex situ oilshale studies conducted by Lawrence Livermore Laboratories 3363. Asillustrated in FIG. 97, the olefin to paraffin ratio appears to increaseas the pyrolysis temperature increases. However, for a fixedtemperature, the ratio decreases rapidly with an increase in pressure.Higher pressures and lower temperatures appear to favor the lowestolefin to paraffin ratios. At a temperature of about 350° C. and apressure of about 7.9 bars absolute 3366, a ratio of olefins toparaffins was approximately 0.01. Pyrolyzing at reduced temperature andincreased pressure may decrease an olefin to paraffin ratio. Pyrolyzinghydrocarbons for a longer period of time, which may be accomplished byincreasing pressure within the system, tends to result in a loweraverage molecular weight oil. In addition, production of gas mayincrease and a non-volatile coke may be formed.

FIG. 98 illustrates a relationship between an API gravity of ahydrocarbon condensate fluid, the partial pressure of molecular hydrogenwithin the fluid, and a temperature within an oil shale formation. Asillustrated in FIG. 98, as a partial pressure of hydrogen within thefluid increased, the API gravity generally increased. In addition, lowerpyrolysis temperatures appear to have increased the API gravity of theproduced fluids. Maintaining a partial pressure of molecular hydrogenwithin a heated portion of a hydrocarbon containing formation mayincrease the API gravity of the produced fluids.

In FIG. 99, a quantity of oil liquids produced in m³ of liquids per kgof oil shale formation is plotted versus a partial pressure of H₂. Alsoillustrated in FIG. 99 are various curves for pyrolysis occurring atdifferent temperatures. At higher pyrolysis temperatures production ofoil liquids was higher than at the lower pyrolysis temperatures. Inaddition, high pressures tended to decrease the quantity of oil liquidsproduced from an oil shale formation. Operating an in situ conversionprocess at low pressures and high temperatures may produce a higherquantity of oil liquids than operating at low temperatures and highpressures.

As illustrated in FIG. 100, an ethene to ethane ratio in the producedgas increased with increasing temperature. In addition, application ofpressure decreased the ethene to ethane ratio significantly. Asillustrated in FIG. 100, lower temperatures and higher pressuresdecreased the ethene to ethane ratio. The ethene to ethane ratio isindicative of the olefin to paraffin ratio in the condensedhydrocarbons.

FIG. 101 illustrates an atomic hydrogen to atomic carbon ratio in thehydrocarbon liquids. In general, lower temperatures and higher pressuresincreased the atomic hydrogen to atomic carbon ratio of the producedhydrocarbon liquids.

A small-scale field experiment of the in-situ process in oil shale wasconducted. An objective of this test was to substantiate laboratoryexperiments that produced high quality crude utilizing the in-situretort process.

As illustrated in FIG. 104, the field experiment consisted of a singleunconfined hexagonal seven spot pattern on eight foot spacing. Six heatinjection wells 3600, drilled to a depth of 40 m, contained 17 m longheating elements that injected thermal energy into the formation from 21m to 39 m. A single producer well 3602 in the center of the patterncaptured the liquids and vapors from the in-situ retort. Threeobservation wells 3603 inside the pattern and one outside the patternrecorded formation temperatures and pressures. Six dewatering wells 3604surrounded the pattern on 6 m spacing and were completed in an activeaquifer below the heated interval (from 44 m to 61 m). FIG. 105 is across-sectional view of the field experiment. A producer well 3602includes pump 3614. A lower portion 3612 of producer well 3602 waspacked with gravel. An upper portion 3610 of producer well 3602 wascemented. Heater well 3600 was located a distance of approximately 2.4meters from producer well 3602. A heating element was located within theheater well and the heater well was cemented in place. Dewatering wells3604 were located approximately 4.0 meters from heater wells 3600.Coring well 3606 was located approximately 0.5 m from heater wells 3600.

Produced oil, gas and water were sampled and analyzed throughout thelife of the experiment. Surface and subsurface pressures andtemperatures and energy injection data were captured electronically andsaved for future evaluation. The composite oil produced from the testhad a 36° API gravity with a low olefin content of 1.1% by weight and aparaffin content of 66% by weight. The composite oil also included asulfur content of 0.4% by weight. This condensate-like crude confirmedthe quality predicted from the laboratory experiments. The compositionof the gas changed throughout the test. The gas was high in hydrogen(average approximately 25 mol %) and CO₂ (average approximately 15 mol%) as expected.

Evaluation of the post heat core indicates that the mahogany zone wasthoroughly retorted except for the top and bottom 1 m to 1.2 m. Oilrecovery efficiency was shown to be in the 75% to 80% range. Someretorting also occurred at least two feet outside of the pattern. Duringthe ICP experiment, the formation pressures were monitored with pressuremonitoring wells. The pressure increased to a highest pressure at 9.4bars absolute and then slowly declined. The high oil quality wasproduced at the highest pressure and temperatures below 350° C. Thepressure was allowed to decrease to atmospheric as temperaturesincreased above 370° C. As predicted, the oil composition under theseconditions was shown to be of lower API gravity, higher molecularweight, greater carbon numbers in carbon number distribution, higherolefin content, and higher sulfur and nitrogen contents.

FIG. 106 illustrates a plot of the maximum temperatures within each ofthe three inner-most observation wells 3603 (see FIG. 104) versus time.The temperature profiles were very similar for the three observationwells. Heat was provided to the oil shale formation for 216 days. Asillustrated in FIG. 106, the temperature at the observer wells increasedsteadily until the heat was turned off.

FIG. 175 illustrates a plot of hydrocarbon liquids production, inbarrels per day, for the same in situ experiment. In this figure theline marked as “Separator Oil” indicates the hydrocarbon liquids thatwere produced after the produced fluids were cooled to ambientconditions and separated. In this figure the line marked as “Oil &C5+Gas Liquids” includes the hydrocarbon liquids produced after theproduced fluids were cooled to ambient conditions and separated and, inaddition, the assessed C₅ and heavier compounds that were flared. Thetotal liquid hydrocarbons produced to a stock tank during the experimentwas 194 barrels. The total equivalent liquid hydrocarbons produced(including the C₅ and heavier compounds) was 250 barrels. As indicatedin FIG. 175 the heat was turned off at day 216, however somehydrocarbons continued to be produced thereafter.

FIG. 176 illustrates a plot of production of hydrocarbon liquids (inbarrels per day), gas (in MCF per day), and water (in barrels per day),versus heat energy injected (in mega Watt-hours), during the same insitu experiment. As shown in FIG. 176 the heat was turned off afterabout 440 megawatt-hours of energy had been injected.

As illustrated in FIG. 107, pressure within the oil shale materialshowed some variations initially at different depths, however over timethese variations equalized. FIG. 107 depicts the gauge fluid pressure inthe observation well 3603 versus time measured in days at a radialdistance of 2.1 m from the production well 3602. The fluid pressureswere monitored at depths of 24 m and 33 m. These depths corresponded toa richness within the oil shale material of 8.3×10⁻⁵ m³ of oil/kg of oilshale at 24 m and 1.7×10⁻⁴ m³ of oil/kg of oil shale at 33 m. The higherpressures initially observed at 33 m may be the result of a highergeneration of fluids due to the richness of the oil shale material atthat depth. In addition, at lower depths a lithostatic pressure may behigher, causing the oil shale material at 33 m to fracture at higherpressure than at 24 m. During the course of the experiment, pressureswithin the oil shale formation equalized. The equalization of thepressure may have resulted from fractures forming within the oil shaleformation.

FIG. 108 is a plot of API gravity versus time measured in days. Asillustrated in FIG. 108, the API gravity was relatively high (i.e.,hovering around 40° until about 140 days). The API gravity, although itstill varied, decreased steadily thereafter. Prior to 110 days thepressure measured at shallower depths was increasing, and after 110 daysit began to decrease significantly. At about 140 days the pressure atthe deeper depths began to decrease. At about 140 days the temperatureas measured at the observation wells increased above about 370° C.

In FIG. 109 average carbon numbers of the produced fluid are plottedversus time measured in days. At approximately 140 days, the averagecarbon number of the produced fluids increased. This approximatelycorresponded to the temperature rise and the drop in pressureillustrated in FIG. 106 and FIG. 107, respectively. In addition, asdemonstrated in FIG. 110 the density of the produced hydrocarbonliquids, in grams per cc, increased at approximately 140 days. Thequality of the produced hydrocarbon liquids as demonstrated in FIG. 108,FIG. 109, and FIG. 110 decreased as the temperature increased and thepressure decreased.

FIG. 111 depicts a plot of the weight percent of specific carbon numbersof hydrocarbons within the produced hydrocarbon liquids. The variouscurves represent different times at which the liquids were produced. Thecarbon number distribution of the produced hydrocarbon liquids for thefirst 136 days exhibited a relatively narrow carbon number distribution,with a low weight percent of carbon numbers above 16. The carbon numberdistribution of the produced hydrocarbon liquids becomes progressivelybroader as time progresses after 136 days (e.g., from 199 days to 206days to 231 days). As the temperature continued to increase, and thepressure had decreased towards one atmosphere absolute, the productquality steadily deteriorated.

FIG. 112 illustrates a plot of the weight percent of specific carbonnumbers of hydrocarbons within the produced hydrocarbon liquids. Curve3620 represents the carbon distribution for the composite mixture ofhydrocarbon liquids over the entire in situ conversion process (“ICP”)field experiment. For comparison, a plot of the carbon numberdistribution for hydrocarbon liquids produced from a surface retort ofthe same Green River oil shale is also depicted as curve 3622. In thesurface retort, oil shale was mined, placed in a vessel, rapidly heatedat atmospheric pressure to a high temperature in excess of 500° C. Asillustrated in FIG. 112, a carbon number distribution of the majority ofthe hydrocarbon liquids produced from the ICP field experiment waswithin a range of 8 to 15. The peak carbon number from production of oilduring the ICP field experiment was about 13. In contrast, the surfaceretort 3622 has a relatively flat carbon number distribution with asubstantial amount of carbon numbers greater than 25.

During the ICP experiment, the formation pressures were monitored withpressure monitoring wells. The pressure increased to a highest pressureat 9.3 bars absolute and then slowly declined. The high oil quality wasproduced at the highest pressures and temperatures below 350° C. Thepressure was allowed to decrease to atmospheric as temperaturesincreased above 370° C. As predicted, the oil composition under theseconditions was shown to be of lower API gravity, higher molecularweight, greater carbon numbers in carbon number distribution, higherolefin content, and higher sulfur and nitrogen contents.

Experimental data from studies conducted by Lawrence Livermore NationalLaboratories (LLNL) was plotted along with laboratory data from the insitu conversion process (ICP) for an oil shale formation at atmosphericpressure in FIG. 113. The oil recovery as a percent of Fischer assay wasplotted against a log of the heating rate. Data from LLNL 3642 includeddata derived from pyrolyzing powdered oil shale at atmospheric pressureand in a range from about 2 bars absolute to about 2.5 bars absolute. Asillustrated in FIG. 113, the data from LLNL 3642 has a linear trend.Data from the ICP 3640 demonstrates that oil recovery, as measured byFischer assay, was much higher for ICP than the data from LLNL wouldsuggest 3642. FIG. 113 demonstrates that oil recovery from oil shaleincreases along an S-curve.

Results from the oil shale field experiment (e.g., measured pressures,temperatures, produced fluid quantities and compositions, etc.) wereinputted into a numerical simulation model in order to attempt to assessformation fluid transport mechanisms. FIG. 114 shows the results fromthe computer simulation. In FIG. 114, oil production 3670 in stock tankbarrels/day was plotted versus time. Area 3674 represents the liquidhydrocarbons in the formation at reservoir conditions that were measuredin the field experiment. FIG. 114 indicates that more than 90% of thehydrocarbons in the formation were vapors. Based on these results, andthe fact that the wells in the field test produced mostly vapors (untilsuch vapors were cooled, at which point hydrocarbon liquids wereproduced), it is believed that hydrocarbons in the formation movethrough the formation as vapors when heated as is described above forthe oil shale field experiment.

A series of experiments was conducted to determine the effects ofvarious properties of hydrocarbon containing formations on properties offluids produced from coal formations. The fluids may be producedaccording to any of the embodiments as described herein. The series ofexperiments included organic petrography, proximate/ultimate analyses,Rock-Eval pyrolysis, Leco Total Organic Carbon (“TOC”), Fischer Assay,and pyrolysis-gas chromatography. Such a combination of petrographic andchemical techniques may provide a quick and inexpensive method fordetermining physical and chemical properties of coal and for providing acomprehensive understanding of the effect of geochemical parameters onpotential oil and gas production from coal pyrolysis. The series ofexperiments were conducted on forty-five cubes of coal to determinesource rock properties of each coal and to assess potential oil and gasproduction from each coal.

Organic petrology is the study, mostly under the microscope, of theorganic constituents of coal and other rocks. The petrography of coal isimportant since it affects the physical and chemical nature of the coal.The ultimate analysis refers to a series of defined methods that areused to determine the carbon, hydrogen, sulfur, nitrogen, ash, oxygen,and the heating value of a coal. Proximate analysis is the measurementof the moisture, ash, volatile matter, and fixed carbon content of acoal.

Rock-Eval pyrolysis is a petroleum exploration tool developed to assessthe generative potential and thermal maturity of prospective sourcerocks. A ground sample may be pyrolyzed in a helium atmosphere. Forexample, the sample may be initially heated and held at a temperature of300° C. for 5 minutes. The sample may be further heated at a rate of 25°C./min to a final temperature of 600° C. The final temperature may bemaintained for 1 minute. The products of pyrolysis may be oxidized in aseparate chamber at 580° C. to determined the total organic carboncontent. All components generated may be split into two streams passingthrough a flame ionization detector, which measures hydrocarbons, and athermal conductivity detector, which measures CO₂.

Leco Total Organic Carbon (“TOC”) involves combustion of coal. Forexample, a small sample (about 1 gram) is heated to 1500° C. in ahigh-frequency electrical field under an oxygen atmosphere. Conversionof carbon to carbon dioxide is measured volumetrically. Pyrolysis-gaschromatography may be used for quantitative and qualitative analysis ofpyrolysis gas.

Coal of different ranks and vitrinite reflectances were treated in alaboratory to simulate an in situ conversion process. The different coalsamples were heated at a rate of about 2° C./day and at a pressure of 1bar or 4.4 bars absolute. FIG. 115 shows weight percents of paraffinsplotted against vitrinite reflectance. As shown in FIG. 115, weightpercent of paraffins in the produced oil increases at vitrinitereflectances of the coal below about 0.9%. In addition, a weight percentof paraffins in the produced oil approaches a maximum at a vitrinitereflectance of about 0.9%. FIG. 116 depicts weight percentages ofcycloalkanes in the produced oil plotted versus vitrinite reflectance.As shown in FIG. 116, a weight percent of cycloalkanes in the oilproduced increased as vitrinite reflectance increased. Weightpercentages of a sum of paraffins and cycloalkanes is plotted versusvitrinite reflectance in FIG. 117. In some embodiments, an in situconversion process may be utilized to produce phenol. Phenol generationmay increase when a fluid pressure within the formation is maintained ata lower pressure. Phenol weight percent in the produced oil is depictedin FIG. 118. A weight percent of phenol in the produced oil decreases asthe vitrinite reflectance increases. FIG. 119 illustrates a weightpercentage of aromatics in the hydrocarbon fluids plotted againstvitrinite reflectance. As shown in FIG. 119, a weight percent ofaromatics in the produced oil decreases below a vitrinite reflectance ofabout 0.9%. A weight percent of aromatics in the produced oil increasesabove a vitrinite reflectance of about 0.9%. FIG. 120 depicts a ratio ofparaffins to aromatics 3680 and a ratio of aliphatics to aromatics 3682plotted versus vitrinite reflectance. Both ratios increase to a maximumat a vitrinite reflectance between about 0.7% and about 0.9%. Above avitrinite reflectance of about 0.9%, both ratios decrease as vitrinitereflectance increases.

FIG. 134 depicts the condensable hydrocarbon compositions, andcondensable hydrocarbon API gravities, that were produced when variousranks of coal were treated as is described above for FIGS. 115-120. InFIG. 134, “SubC” means a rank of sub-bituminous C coal, “SubB” means arank of sub-bituminous B coal, “SubA” refers to a rank of sub-bituminousA coal, “HVC” refers to a rank of high volatile bituminous C coal,“HVBA” refers to a rank of high volatile bituminous coal at the borderbetween B and A rank coal, “MV” refers to a rank medium volatilebituminous coal, and “Ro” refers to vitrinite reflectance. As can beseen in FIG. 134, certain ranks of coal will produce differentcompositions when treated in certain embodiments described herein. Forinstance, in many circumstances it may be desirable to treat coal havinga rank of HVBA because such coal, when treated, has the highest APIgravity, the highest weight percent of paraffins, and the highest weightpercent of the sum of paraffins and cycloalkanes.

Results were also displayed as a yield of products. FIGS. 121-124illustrate the yields of components in terms of m³ of product per kg ofhydrocarbon containing formation, when measured on a dry, ash freebasis. As illustrated in FIG. 121 the yield of paraffins increased asthe vitrinite reflectance of the coal increased. However, for coals witha vitrinite reflectance greater than about 0.7 to 0.8% the yield ofparaffins fell off dramatically. In addition, a yield of cycloalkanesfollowed similar trends as the paraffins, increasing as the vitrinitereflectance of coal increased and decreasing for coals with a vitrinitereflectance greater than about 0.7% or 0.8% as illustrated in FIG. 122.FIG. 123 illustrates the increase of both paraffins and cycloalkanes asthe vitrinite reflectance of coal increases to about 0.7% or 0.8%. Asillustrated in FIG. 124, the yield of phenols may be relatively low forcoal material with a vitrinite reflectance of less than about 0.3% andgreater than about 1.25%. Production of phenols may be desired due tothe value of phenol as a feedstock for chemical synthesis.

As demonstrated in FIG. 125, the API gravity appears to increasesignificantly when the vitrinite reflectance is greater than about 0.4%.FIG. 126 illustrates the relationship between coal rank, (i.e.,vitrinite reflectance), and a yield of condensable hydrocarbons (ingallons per ton on a dry ash free basis) from a coal formation. Theyield in this experiment appears to be in an optimal range when the coalhas a vitrinite reflectance greater than about 0.4% to less than about1.3%.

FIG. 127 illustrates a plot of CO₂ yield of coal having variousvitrinite reflectances. In FIGS. 127 and 128, CO₂ yield is set forth inweight percent on a dry ash free basis. As shown in FIG. 127, at leastsome CO₂ was released from all of the coal samples. Such CO₂ productionmay correspond to various oxygenated functional groups present in theinitial coal samples. A yield of CO₂ produced from low-rank coal sampleswas significantly higher than a production from high-rank coal samples.Low-rank coals may include lignite and sub-bituminous brown coals.High-rank coals may include semi-anthracite and anthracite coal. FIG.128 illustrates a plot of CO₂ yield from a portion of a coal formationversus the atomic O/C ratio within a portion of a coal formation. As O/Catomic ratio increases, a CO₂ yield increases.

Results were also displayed as a yield of products. FIGS. 121-124illustrate the yields of components in terms of m³ of product per kg ofhydrocarbon containing formation, when measured on a dry, ash freebasis. As illustrated in FIG. 121 the yield of paraffins increased asthe vitrinite reflectance of the coal increased. However, for coals witha vitrinite reflectance greater than about 0.7 to 0.8% the yield ofparaffins fell off dramatically. In addition, a yield of cycloalkanesfollowed similar trends as the paraffins, increasing as the vitrinitereflectance of coal increased and decreasing for coals with a vitrinitereflectance greater than about 0.7% or 0.8% as illustrated in FIG. 122.FIG. 123 illustrates the increase of both paraffins and cycloalkanes asthe vitrinite reflectance of coal increases to about 0.7% or 0.8%. Asillustrated in FIG. 124, the yield of phenols may be relatively low forcoal material with a vitrinite reflectance of less than about 0.3% andgreater than about 1.25%. Production of phenols may be desired due tothe value of phenol as a feedstock for chemical synthesis.

As demonstrated in FIG. 125, the API gravity appears to increasesignificantly when the vitrinite reflectance is greater than about 0.4%.FIG. 126 illustrates the relationship between coal rank, (i.e.,vitrinite reflectance), and a yield of condensable hydrocarbons (ingallons per ton on a dry ash free basis) from a coal formation. Theyield in this experiment appears to be in an optimal range when the coalhas a vitrinite reflectance greater than about 0.4% to less than about1.3%.

FIG. 127 illustrates a plot of CO₂ yield of coal having variousvitrinite reflectances. In FIGS. 127 and 128, CO₂ yield is set forth inweight percent on a dry ash free basis. As shown in FIG. 127, at leastsome CO₂ was released from all of the coal samples. Such CO₂ productionmay correspond to various oxygenated functional groups present in theinitial coal samples. A yield of CO₂ produced from low-rank coal sampleswas significantly higher than a production from high-rank coal samples.Low-rank coals may include lignite and sub-bituminous brown coals.High-rank coals may include semi-anthracite and anthracite coal. FIG.128 illustrates a plot of CO₂ yield from a portion of a coal formationversus the atomic O/C ratio within a portion of a coal formation. As O/Catomic ratio increases, a CO₂ yield increases.

A slow heating process may produce condensed hydrocarbon fluids havingAPI gravities in a range of 22° to 50°, and average molecular weights ofabout 150 g/gmol to about 250 g/gmol. These properties may be comparedto properties of condensed hydrocarbon fluids produced by ex situretorting of coal as reported in Great Britain Published PatentApplication No. GB 2,068,014 A, which is incorporated by reference as iffully set forth herein. For example, properties of condensed hydrocarbonfluids produced by an ex situ retort process include API gravities of1.9° to 7.9° produced at temperatures of 521° C. and 427° C.,respectively.

Table 4 shows a comparison of gas compositions, in percent volume,obtained from in situ gasification of coal using air injection to heatthe coal, in situ gasification of coal using oxygen injection to heatthe coal, and in situ gasification of coal in a reducing atmosphere bythermal pyrolysis heating as described in embodiments herein.

TABLE 4 Gasification Gasification Thermal Pyrolysis With Air With OxygenHeating H₂ 18.6% 35.5% 16.7% Methane 3.6% 6.9% 61.9% Nitrogen and Argon47.5% 0.0 0.0 Carbon Monoxide 16.5% 31.5% 0.9% Carbon Dioxide 13.1%25.0% 5.3% Ethane 0.6% 1.1% 15.2%

As shown in Table 4, gas produced according to an embodiment describedherein may be treated and sold through existing natural gas systems. Incontrast, gas produced by typical in situ gasification processes may notbe treated and sold through existing natural gas systems. For example, aheating value of the gas produced by gasification with air was 6000KJ/m³, and a heating value of gas produced by gasification with oxygenwas 11,439 KJ/m³. In contrast, a heating value of the gas produced bythermal conductive heating was 39,159 KJ/m³.

Experiments were conducted to determine the difference between treatingrelatively large solid blocks of coal versus treating relatively smallloosely packed particles of coal.

As illustrated in FIG. 129, coal 3700 in the shape of a cube was heatedto pyrolyze the coal. Heat was provided to cube 3700 from heat source3704 inserted into the center of the cube and also from heat sources3702 located on the sides of the cube. The cube was surrounded byinsulation 3705. The temperature was raised simultaneously using heatsources 3704, 3702 at a rate of about 2° C./day at atmospheric pressure.Measurements from temperature gauges 3706 were used to determine anaverage temperature of cube 3700. Pressure in cube 3700 was monitoredwith pressure gauge 3708. The fluids produced from the cube of coal werecollected and routed through conduit 3709. Temperature of the productfluids was monitored with temperature gauge 3706 on conduit 3709. Apressure of the product fluids was monitored with pressure gauge 3708 onconduit 3709. A hydrocarbon condensate was separated from anon-condensable fluid in separator 3710. Pressure in separator 3710 wasmonitored with pressure gauge 3708. A portion of the non-condensablefluid was routed through conduit 3711 to gas analyzers 3712 forcharacterization. Grab samples were taken from a grab sample port 3714.Temperature of the non-condensable fluids was monitored with temperaturegauge 3706 on conduit 3711. A pressure of the non-condensable fluids wasmonitored with pressure gauge 3708 on conduit 3711. The remaining gaswas routed through a flow meter 3716, a carbon bed 3718, and vented tothe atmosphere. The produced hydrocarbon condensate was collected andanalyzed to determine the composition of the hydrocarbon condensate.

FIG. 102 illustrates a drum experimental apparatus. This apparatus wasused to test coal. Electrical heater 3404 and bead heater 3402 were usedto uniformly heat contents of drum 3400. Insulation 3405 surrounds drum3400. Contents of drum 3400 were heated at a rate of about 2° C./day atvarious pressures. Measurements from temperature gauges 3406 were usedto determine an average temperature in drum 3400. Pressure in the drumwas monitored with pressure gauge 3408. Product fluids were removed fromdrum 3400 through conduit 3409. Temperature of the product fluids wasmonitored with temperature gauge 3406 on conduit 3409. A pressure of theproduct fluids was monitored with pressure gauge 3408 on conduit 3409.Product fluids were separated in separator 3410. Separator 3410separated product fluids into condensable and non-condensable products.Pressure in separator 3410 was monitored with pressure gauge 3408.Non-condensable product fluids were removed through conduit 3411. Acomposition of a portion of non-condensable product fluids removed fromseparator 3410 was determined by gas analyzer 3412. A portion ofcondensable product fluids were removed from separator 3410.Compositions of the portion of condensable product fluids collected weredetermined by external analysis methods. Temperature of thenon-condensable fluids was monitored with temperature gauge 3406 onconduit 3411. A pressure of the non-condensable fluids was monitoredwith pressure gauge 3408 on conduit 3411. Flow of non-condensable fluidsfrom separator 3410 was determined by flow meter 3416. Fluids measuredin flow meter 3416 were collected and neutralized in carbon bed 3418.Gas samples were collected in gas container 3414.

A large block of high volatile bituminous B Fruitland coal was separatedinto two portions. One portion (about 550 kg) was ground into smallpieces and tested in a coal drum. The coal was ground to an approximatediameter of about 6.34×10⁻⁴ m. The results of such testing are depictedwith the circles in FIGS. 131 and 133. One portion (a cube having sidesmeasuring 0.3048 m) was tested in a coal cube experiment. The results ofsuch testing are depicted with the squares in FIGS. 131 and 133.

FIG. 131 is a plot of gas phase compositions from experiments on a coalcube and a coal drum for H₂ 3724, methane 3726, ethane 3780, propane3781, n-butane 3782, and other hydrocarbons 3783 as a function oftemperature. As can be seen for FIG. 131, the non condensable fluidsproduced from pyrolysis of the cube and the drum had similarconcentrations of the various hydrocarbons generated within the coal. InFIG. 131 these results were so similar that only one line was drawn forethane 3780, propane 3781, n-butane 3782, and other hydrocarbons 3783for both the cube and the drum results, and the two lines that weredrawn for H₂ (3724 a and 3724 b) and the two lines drawn for methane(3726 a and 3726 b) were in both instances very close to each other.Crushing the coal did not have an apparent effect on the pyrolysis ofthe coal. The peak in methane production 3726 occurred at about 450° C.At higher temperatures methane cracks to hydrogen, so the methaneconcentration decreases while the hydrogen content 3724 increases.

FIG. 132 illustrates a plot of cumulative production of gas as afunction of temperature from heating coal in the cube and coal in thedrum. Line 3790 represents gas production from coal in the drum and line3791 represents gas production from coal in the cube. As demonstrated byFIG. 132, the production of gas in both experiments yielded similarresults, even though the particle sizes were dramatically differentbetween the two experiments.

FIG. 133 illustrates cumulative condensable hydrocarbons produced in thecube and drum experiments. Line 3720 represents cumulative condensablehydrocarbons production from the cube experiment, and line 3722represents cumulative condensable hydrocarbons production from the drumexperiment. As demonstrated by FIG. 133, the production of condensablehydrocarbons in both experiments yielded similar results, even thoughthe particle sizes were dramatically different between the twoexperiments. Production of condensable hydrocarbons is substantiallycomplete when the temperature reached about 390° C. In both experimentsthe condensable hydrocarbons had an API gravity of about 37 degrees.

As shown in FIG. 131, methane started to be produced at temperatures ator above about 270° C. Since the experiments were conduced atatmospheric pressure, it is believed that the methane is produced fromthe pyrolysis, and not from mere desorption. Between about 270° C. andabout 400° C., condensable hydrocarbons, methane and H₂ were produced asshown in FIGS. 131, 132, and 133. FIG. 131 shows that above atemperature of about 400° C. methane and H₂ continue to be produced.Above about 450° C., however, methane concentration decreased in theproduced gases whereas the produced gases contained increased amounts ofH₂. If heating were continued, eventually all H₂ remaining in the coalwould be depleted, and production of gas from the coal would cease.FIGS. 131-133 indicate that the ratio of a yield of gas to a yield ofcondensable hydrocarbons will increase as the temperature increasesabove about 390° C.

FIGS. 131-133 demonstrate that particle size did not substantiallyaffect the quality of condensable hydrocarbons produced from the treatedcoal, the quantity of condensable hydrocarbons produced from the treatedcoal, the amount of gas produced from the treated coal, the compositionof the gas produced from the treated coal, the time required to producethe condensable hydrocarbons and gas from the treated coal, or thetemperatures required to produce the condensable hydrocarbons and asfrom the treated coal. In essence a block of coal yielded substantiallythe same results from treatment as small particles of coal. As such, itis believed that scale-up issues when treating coal will notsubstantially affect treatment results.

An experiment was conducted to determine an effect of heating on thermalconductivity and thermal diffusivity of a portion of a coal formation.Thermal pulse tests performed in situ in a high volatile bituminous Ccoal at the field pilot site showed a thermal conductivity between2.0×10⁻³ to 2.39×10⁻³ cal/cm sec ° C. (0.85 to 1.0 W/(m ° K.)) at 20° C.Ranges in these values were due to different measurements betweendifferent wells. The thermal diffusivity was 4.8×10⁻³ cm²/s at 20° C.(the range was from about 4.1×10⁻³ to about 5.7×10⁻³ cm²/s at 20° C.).It is believed that these measured values for thermal conductivity andthermal diffusivity are substantially higher than would be expectedbased on literature sources (e.g., about three times higher in manyinstances).

An initial value for thermal conductivity from the in situ experiment isplotted versus temperature in FIG. 135 (this initial value is point 3743in FIG. 135). Additional points for thermal conductivity (i.e., all ofthe other values for line 3742 shown in FIG. 135) were assessed bycalculating thermal conductivities using temperature measurements in allof the wells shown in FIG. 137, total heat input from all heaters shownin FIG. 137, measured heat capacity and density for the coal beingtreated, gas and liquids production data (e.g., composition, quantity,etc.), etc. For comparison, these assessed thermal conductivity values(see line 3742) were plotted with data reported in two papers from S.Badzioch, et al. (1964) and R. E. Glass (1984) (see line 3740). Asillustrated in FIG. 135, the assessed thermal conductivities from the insitu experiment were higher than reported values for thermalconductivities. The difference may be at least partially accounted forif it is assumed that the reported values do not take into considerationthe confined nature of the coal in an in situ application. Because thereported values for thermal conductivity of coal are relatively low,they discourage the use of in situ heating for coal.

FIG. 135 illustrates a decrease in the assessed thermal conductivityvalues 3742 at about 100° C. It is believed that this decrease inthermal conductivity was caused by water vaporizing in the cracks andvoid spaces (water vapor has a lower thermal conductivity than liquidwater). At about 350° C., the thermal conductivity began to increase,and it increased substantially as the temperature increased to 700° C.It is believed that the increases in thermal conductivity were theresult of molecular changes in the carbon structure. As the carbon washeated it became more graphitic, which is illustrated in Table 5 by anincreased vitrinite reflectance after pyrolysis. As void spacesincreased due to fluid production, heat was increasingly transferred byradiation and/or convection. In addition, concentrations of hydrogen inthe void spaces were raised due to pyrolysis and generation of synthesisgas.

Three data points 3744 of thermal conductivities under high stress werederived from laboratory tests on the same high volatile bituminous Ccoal used for the in situ field pilot site (see FIG. 135). In thelaboratory tests a sample of such coal was stressed from all directions,and heated relatively quickly. These thermal conductivities weredetermined at higher stress (i.e., 27.6 bars absolute), as compared tothe stress in the in situ field pilot (which were about 3 barsabsolute). Thermal conductivity values 3744 demonstrate that theapplication of stress increased the thermal conductivity of the coal attemperatures of 150° C., 250° C. and 350° C. It is believed that higherthermal conductivity values were obtained from stressed coal because thestress closed at least some cracks/void spaces and/or prevented newcracks/void spaces from forming.

Using the reported values for thermal conductivity and thermaldiffusivity of coal and a 12 m heat source spacing on an equilateraltriangle pattern, calculations show that a heating period of about tenyears would be needed to raise an average temperature of coal to about350° C. Such a heating period may not be economically viable. Usingexperimental values for thermal conductivity and thermal diffusivity andthe same 12 m heat source spacing, calculations show that the heatingperiod to reach an average temperature of 350° C. would be about 3years. The elimination of about 7 years of heating a formation will inmany instances significantly improve the economic viability of an insitu conversion process for coal.

Molecular hydrogen has a relatively high thermal conductivity (e.g., thethermal conductivity of molecular hydrogen is about 6 times the thermalconductivity of nitrogen or air). Therefore it is believed that as theamount of hydrogen in the formation void spaces increases, the thermalconductivity of the formation will also increase. The increases inthermal conductivity due to the presence of hydrogen in the void spacessomewhat offsets decreases in thermal conductivity caused by the voidspaces themselves. It is believed that increases in thermal conductivitydue to the presence of hydrogen will be larger for coal formations ascompared to other hydrocarbon containing formations since the amount ofvoid spaces created during pyrolysis will be larger (coal has a higherhydrocarbon density, so pyrolysis creates more void spaces in coal).

Hydrocarbon fluids were produced from a portion of a coal formation byan in situ experiment conducted in a portion of a coal formation. Thecoal was high volatile bituminous C coal. It was heated with electricalheaters. FIG. 136 illustrates a cross-sectional view of the in situexperimental field test system. As shown in FIG. 136, the experimentalfield test system included coal formation 3802 within the ground andgrout wall 3800. Coal formation 3802 dipped at an angle of approximately36° with a thickness of approximately 4.9 meters. FIG. 137 illustrates alocation of heat sources 3804 a, 3804 b, 3804 c, production wells 3806a, 3806 b, and temperature observation wells 3808 a, 3808 b, 3808 c,3808 d used for the experimental field test system. The three heatsources were disposed in a triangular configuration. Production well3806 a was located proximate a center of the heat source pattern andequidistant from each of the heat sources. A second production well 3806b was located outside the heat source pattern and spaced equidistantfrom the two closest heat sources. Grout wall 3800 was formed around theheat source pattern and the production wells. The grout wall was formedof 24 pillars. Grout wall 3800 was configured to inhibit an influx ofwater into the portion during the in situ experiment. In addition, groutwall 3800 was configured to substantially inhibit loss of generatedhydrocarbon fluids to an unheated portion of the formation.

Temperatures were measured at various times during the experiment ateach of four temperature observation wells 3808 a, 3808 b, 3808 c, 3808d located within and outside of the heat source pattern as illustratedin FIG. 137. The temperatures measured (in degrees Celsius) at each ofthe temperature observation wells are displayed in FIG. 138 as afunction of time. Temperatures at observation wells 3808 a (3820), 3808b (3822), and 3808 c (3824) were relatively close to each other. Atemperature at temperature observation well 3808 d (3826) wassignificantly colder. This temperature observation well was locatedoutside of the heater well triangle illustrated in FIG. 137. This datademonstrates that in zones where there was little superposition of heat,temperatures were significantly lower. FIG. 139 illustrates temperatureprofiles measured at the heat sources 3804 a (3830), 3804 b (3832), and3804 c (3834). The temperature profiles were relatively uniform at theheat sources.

FIG. 140 illustrates a plot of cumulative volume (m³) of liquidhydrocarbons produced 3840 as a function of time (days). FIG. 149illustrates a plot of cumulative volume of gas produced 3910 in standardcubic feet, produced as a function of time (in days) for the same insitu experiment. Both FIG. 140 and FIG. 149 show the results during thepyrolysis stage only of the in situ experiment.

FIG. 141 illustrates the carbon number distribution of condensablehydrocarbons that were produced using slow, low temperature retortingprocess as described above. As can be seen in FIG. 141, relatively highquality products were produced during treatment. The results in FIG. 141are consistent with the results set forth in FIG. 146, which showresults from heating coal from the same formation in the laboratory forsimilar ranges of heating rates as were used in situ.

Table 5 illustrates the results from analyzing coal before and after itwas treated (including heating to the temperatures as set forth in FIG.139 (i.e., after pyrolysis and production of synthesis gas)) asdescribed above. The coal was cored at about 11-11.3 meters from thesurface, midway into the coal bed, in both the “before treatment” and“after treatment” examples. Both cores were taken at about the samelocation. Both cores were taken at about 0.66 meters from well 3804 c(between the grout wall and well 3804 c) in FIG. 137. In the followingTable 5 “FA” means Fisher Assay, “as rec'd” means the sample was testedas it was received and without any further treatment, “Py-Water” meansthe water produced during pyrolysis, “H/C Atomic Ratio” means the atomicratio of hydrogen to carbon, “daf” means “dry ash free,” “dmmf” means“dry mineral matter free,” and “mmf” means “mineral matter free.” Thespecific gravity of the “after treatment” core sample was approximately0.85 whereas the specific gravity of the “before treatment” core samplewas approximately 1.35.

TABLE 5 Analysis Before Treatment After Treatment % VitriniteReflectance 0.54 5.16 FA (gal/ton, as-rec'd) 11.81 0.17 FA (wt %, asrec'd) 6.10 0.61 FA Py-Water (gal/ton, as-rec'd) 10.54 2.22 H/C AtomicRatio 0.85 0.06 H (wt %, daf) 5.31 0.44 O (wt %, daf) 17.08 3.06 N (wt%, daf) 1.43 1.35 Ash (wt %, as rec'd) 32.72 56.50 Fixed Carbon (wt %,dmmf) 54.45 94.43 Volatile Matter (wt %, dmmf) 45.55 5.57 Heating Value(Btu/lb, moist, 12048 14281 mmf)

Even though the cores were taken outside the areas within the triangleformed by the three heaters in FIG. 137, nevertheless the coresdemonstrate that the coal remaining in the formation changedsignificantly during treatment. The vitrinite reflectance results shownin Table 5 demonstrate that the rank of the coal remaining in theformation changed substantially during treatment. The coal was a highvolatile bituminous C coal before treatment. After treatment, however,the coal was essentially anthracite. The Fischer Assay results shown inTable 5 demonstrate that most of the hydrocarbons in the coal had beenremoved during treatment. The H/C Atomic Ratio demonstrates that most ofthe hydrogen in the coal had been removed during treatment. Asignificant amount of nitrogen and ash was left in the formation.

In sum, the results shown in Table 5 demonstrate that a significantamount of hydrocarbons and hydrogen were removed during treatment of thecoal by pyrolysis and generation of synthesis gas. Significant amountsof undesirable products (ash and nitrogen) remain in the formation,while the significant amounts of desirable products (e.g., condensablehydrocarbons and gas) were removed.

FIG. 142 illustrates a plot of weight percent of a hydrocarbon producedversus carbon number distribution for two laboratory experiments on coalfrom the field experiment site. The coal was a high volatile bituminousC coal. As shown in FIG. 142, a carbon number distribution of fluidsproduced from a formation varied depending on, for example, pressure.For example, first pressure 3842 was about I bar absolute and secondpressure 3844 was about 8 bars absolute. The laboratory carbon numberdistribution shown in FIG. 142 was similar to that produced in the fieldexperiment in FIG. 141 also at 1 bar absolute. As shown in FIG. 142, aspressure increased, a range of carbon numbers of the hydrocarbon fluidsdecreased. An increase in products having carbon numbers less than 20was observed when operating at 8 bars absolute. Increasing the pressurefrom 1 bar absolute to 8 bars absolute also increased an API gravity ofthe condensed hydrocarbon fluids. The API gravities of condensedhydrocarbon fluids produced were approximately 23.1° and approximately31.3°, respectively. Such an increase in API gravity representsincreased production of more valuable products.

FIG. 143 illustrates a bar graph of fractions from a boiling pointseparation of hydrocarbon liquids generated by a Fischer assay and aboiling point separation of hydrocarbon liquids from the coal cubeexperiment described herein (see, e.g., the system shown in FIG. 129).The experiment was conducted at a much slower heating rate (2 degreesCelsius per day) and the oil produced at a lower final temperature thanthe Fischer Assay. FIG. 143 shows the weight percent of various boilingpoint cuts of hydrocarbon liquids produced from a Fruitland highvolatile bituminous B coal. Different boiling point cuts may representdifferent hydrocarbon fluid compositions. The boiling point cutsillustrated include naphtha 3860 (initial boiling point to 166° C.), jetfuel 3862 (166° C. to 249° C.), diesel 3864 (249° C. to 370° C.), andbottoms 3866 (boiling point greater than 370° C.). The hydrocarbonliquids from the coal cube were substantially more valuable products.The API gravity of such hydrocarbon liquids was significantly greaterthan the API gravity of the Fischer Assay liquid. The hydrocarbonliquids from the coal cube also included significantly less residualbottoms than were produced from the Fischer Assay hydrocarbon liquids.

FIG. 144 illustrates a plot of percentage ethene, which is an olefin, toethane produced from a coal formation as a function of heating rate.Data points were derived from laboratory experimental data (see systemshown in FIG. 89 and associated text) for slow heating of high volatilebituminous C coal at atmospheric pressure, and from Fischer assayresults. As illustrated in FIG. 144, the ratio of ethene to ethaneincreased as the heating rate increased. As such, it is believed thatdecreasing the heating rate of coal will decrease production of olefins.The heating rate of a formation may be determined in part by thespacings of heat sources within the formation, and by the amount of heatthat is transferred from the heat sources to the formation.

Formation pressure may also have a significant effect on olefinproduction. A high formation pressure may tend to result in theproduction of small quantities of olefins. High pressure within aformation may result in a high H₂ partial pressure within the formation.The high H₂ partial pressure may result in hydrogenation of the fluidwithin the formation. Hydrogenation may result in a reduction of olefinsin a fluid produced from the formation. A high pressure and high H₂partial pressure may also result in inhibition of aromatization ofhydrocarbons within the formation. Aromatization may include formationof aromatic and cyclic compounds from alkanes and/or alkenes within ahydrocarbon mixture. If it is desirable to increase production ofolefins from a formation, the olefin content of fluid produced from theformation may be increased by reducing pressure within the formation.The pressure may be reduced by drawing off a larger quantity offormation fluid from a portion of the formation that is being produced.The pressure may be reduced by drawing a vacuum on the portion of theformation being produced.

The system depicted in FIG. 89, and the method of using such system (seeother discussion herein with respect to using such system to conduct oilshale experiments) was used to conduct experiments on high volatilebituminous C coal when such coal was heated at 5° C./day at atmosphericpressure. FIG. 103 depicts certain data points from such experiment (theline depicted in FIG. 103 was produced from a linear regression analysisof such data points). FIG. 103 illustrates the ethene to ethane molarratio as a function of hydrogen molar concentration in non-condensablehydrocarbons produced from the coal during the experiment. The ethene toethane ratio in the non-condensable hydrocarbons is reflective of olefincontent in all hydrocarbons produced from the coal. As can be seen inFIG. 103, as the concentration of hydrogen autogenously increased duringpyrolysis, the ratio of ethene to ethane decreased. It is believed thatincreases in the concentration (and partial pressure) of hydrogen duringpyrolysis causes the olefin concentration to decrease in the fluidsproduced from pyrolysis.

FIG. 145 illustrates product quality, as measured by API gravity, as afunction of rate of temperature increase of fluids produced from highvolatile bituminous “C” coal. Data points were derived from Fischerassay data and from laboratory experiments. For the Fischer assay data,the rate of temperature increase was approximately 17,100° C./day andthe resulting API gravity was less than 11°. For the relatively slowlaboratory experiments, the rate of temperature increase ranged fromabout 2° C./day to about 10° C./day, and the resulting API gravitiesranged from about 23° to about 26°. A substantially linear decrease inquality (decrease in API gravity) was exhibited as the logarithmicheating rate increased.

FIG. 146 illustrates weight percentages of various carbon numbersproducts removed from high volatile bituminous “C” coal when coal isheated at various heating rates. Data points were derived fromlaboratory experiments and a Fischer assay. Curves for heating at a rateof 2° C./day 3870, 3° C./day 3872, 5° C./day 3874, and 10° C./day 3876provided for similar carbon number distributions in the produced fluids.A coal sample was also heated in a Fischer assay test at a rate of about17,100° C./day. The data from the Fischer assay test is indicated byreference numeral 3878. Slow heating rates resulted in less productionof components having carbon numbers greater than 20 as compared to theFischer assay results 3878. Lower heating rates also produced higherweight percentages of components with carbon numbers less than 20. Thelower heating rates produced large amounts of components having carbonnumbers near 12. A peak in carbon number distribution near 12 is typicalof the in situ conversion process for coal and oil shale.

An experiment was conducted on the coal formation treated according tothe in situ conversion process to measure the uniform permeability ofthe formation after pyrolysis. After heating a portion of the coalformation, a ten minute pulse of CO₂ was injected into the formation atfirst production well 3806 a and produced at well 3804 a, as shown inFIG. 137. The CO₂ tracer test was repeated from production well 3806 ato well 3804 b and from production well 3806 a to well 3804 c. Asdescribed above, each of the three different heat sources were locatedequidistant from the production well. The CO₂ was injected at a rate of4.08 m³ /h (144 standard cubic feet per hour). As illustrated in FIG.147, the CO₂ reached each of the three different heat sources atapproximately the same time. Line 3900 illustrates production of CO₂ atheat source 3804 a, line 3902 illustrates production of CO₂ at heatsource 3804 b, and line 3904 illustrates production of CO₂ at heatsource 3804 c. As shown in FIG. 149, yield of CO₂ 3910 from each of thethree different wells was also approximately equal over time. Suchapproximately equivalent transfer of a tracer pulse of CO₂ through theformation and yield of CO₂ from the formation indicated that theformation was substantially uniformly permeable. The fact that the firstCO₂ arrival only occurs approximately 18 minutes after start of the CO₂pulse indicates that no preferential paths had been created between well3806 a and wells 3804 a, 3804 b, and 3804 c.

The in situ permeability was measured by injecting a gas betweendifferent wells after the pyrolysis and synthesis gas formation stageswere complete. The measured permeability varied from about 4.5 darcy to39 darcy (with an average of about 20 darcy), thereby indicating thatthe permeability was high and relatively uniform. The before-treatmentpermeability was only about 50 millidarcy.

Synthesis gas was also produced in an in situ experiment from theportion of the coal formation shown in FIG. 136 and FIG. 137. In thisexperiment, heater wells were also configured to inject fluids. FIG. 148is a plot of weight of produced volatiles (oil and noncondensable gas)in kilograms as a function of cumulative energy input in kilowatt hourswith regard to the in situ experimental field test. The figureillustrates the quantity and energy content of pyrolysis fluids andsynthesis gas produced from the formation.

FIG. 150 is a plot of the volume of oil equivalent produced (m³) as afunction of energy input into the coal formation (kW·hr) from theexperimental field test. The volume of oil equivalent in cubic meterswas determined by converting the energy content of the volume ofproduced oil plus gas to a volume of oil with the same energy content.

The start of synthesis gas production, indicated by arrow 3912, was atan energy input of approximately 77,000 kW·hr. The average coaltemperature in the pyrolysis region had been raised to 620° C. Becausethe average slope of the curve in FIG. 150 in the pyrolysis region isgreater than the average slope of the curve in the synthesis as region,FIG. 150 illustrates that the amount of useable energy contained in theproduced synthesis gas is less than that contained in the pyrolysisfluids. Therefore, synthesis gas production is less energy efficientthan pyrolysis. There are two reasons for this result. First, the two H₂molecules produced in the synthesis gas reaction have a lower energycontent than low carbon number hydrocarbons produced in pyrolysis.Second, the endothermic synthesis gas reaction consumes energy.

FIG. 151 is a plot of the total synthesis as production (m³/min) fromthe coal formation versus the total water inflow (kg/h) due to injectioninto the formation from the experimental field test results facility.Synthesis gas may be generated in a formation at a synthesis gasgenerating temperature before the injection of water or steam due to thepresence of natural water inflow into hot coal formation. Natural watermay come from below the formation.

From FIG. 151, the maximum natural water inflow is approximately 5 kg/has indicated by arrow 3920. Arrows 3922, 3924, and 3926 representinjected water rates of about 2.7 kg/h, 5.4 kg/h, and 11 kg/h,respectively, into central well 3806 a of FIG. 137. Production ofsynthesis gas is at heater wells 3804 a, 3804 b, and 3804 c. FIG. 151shows that the synthesis gas production per unit volume of waterinjected decreases at arrow 3922 at approximately 2.7 kg/h of injectedwater or 7.7 kg/h of total water inflow. The reason for the decrease isthat steam is flowing too fast through the coal seam to allow thereactions to approach equilibrium conditions.

FIG. 152 illustrates production rate of synthesis gas (m³ /min) as afunction of steam injection rate (kg/h) in a coal formation. Data 3930for a first run corresponds to injection at producer well 3806 a in FIG.137, and production of synthesis gas at heater wells 3804 a, 3804 b, and3804 c. Data 3932 for a second run corresponds to injection of steam atheater well 3804 c, and production of additional gas at a productionwell 3806 a. Data 3930 for the first run corresponds to the data shownin FIG. 151. As shown in FIG. 152, the injected water is in reactionequilibrium with the formation to about 2.7 kg/h of injected water. Thesecond run results in substantially the same amount of additionalsynthesis gas produced, shown by data 3932, as the first run to about1.2 kg/h of injected steam. At about 1.2 kg/h, data 3930 starts todeviate from equilibrium conditions because the residence time isinsufficient for the additional water to react with the coal. Astemperature is increased, a greater amount of additional synthesis gasis produced for a given injected water rate. The reason is that athigher temperatures the reaction rate and conversion of water intosynthesis gas increases.

FIG. 153 is a plot that illustrates the effect of methane injection intoa heated coal formation in the experimental field test (all of the unitsin FIGS. 153-156 are in m³ per hour). FIG. 153 demonstrates hydrocarbonsadded to the synthesis gas producing fluid are cracked within theformation. FIG. 137 illustrates the layout of the heater and productionwells at the field test facility. Methane was injected into productionwells 3806 a and 3806 b and fluid was produced from heater wells 3804 a,3804 b, and 3804 c. The average temperatures measured at various wellswere as follows: 3804 a (746° C.), 3804 b (746° C.), 3804 c (767° C.),3808 a (592° C.), 3808 b (573° C.), 3808 c (606° C.), and 3806 a (769°C.). When the methane contacted the formation, it cracked within theformation to produce H₂ and coke. FIG. 153 shows that as the methaneinjection rate increased, the production of H₂ 3940 increased. Thisindicated that methane was cracking to form H₂. Methane production 3942also increased which indicates that not all of the injected methane iscracked. The measured compositions of ethane, ethene, propane, andbutane were negligible.

FIG. 154 is a plot that illustrates the effect of ethane injection intoa heated coal formation in the experimental field test. Ethane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturesmeasured at various wells were as follows: 3804 a (742° C.), 3804 b(750° C.), 3804 c (744° C.), 3808 a (611° C.), 3808 b (595° C.), 3808 c(626° C.), and 3806 a (818° C.). When ethane contacted the formation, itcracked to produce H₂, methane, ethene, and coke. FIG. 154 shows that asthe ethane injection rate increased, the production of Ha 3950, methane3952, ethane 3954, and ethene 3956 increased. This indicates that ethaneis cracking to form H₂ and low molecular weight hydrocarbons. Theproduction rate of higher carbon number products (i.e., propane andpropylene) were unaffected by the injection of ethane.

FIG. 155 is a plot that illustrates the effect of propane injection intoa heated coal formation in the experimental field test. Propane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturesmeasured at various wells were as follows: 3804 a (737° C.), 3804 b(753° C.), 3804 c (726° C.), 3808 a (589° C.), 3808 b (573° C.), 3808 c(606° C.), and 3806 a (769° C.). When propane contacted the formation,it cracked to produce H₂, methane, ethane, ethene, propylene and coke.FIG. 155 shows that as the propane injection rate increased, theproduction of H₂ 3960, methane 3962, ethane 3964, ethene 3966, propane3968, and propylene 3969 increased. This indicates that propane iscracking to form H₂ and lower molecular weight components.

FIG. 156 is a plot that illustrates the effect of butane injection intoa heated coal formation in the experimental field test. Butane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturemeasured at various wells were as follows: 3804 a (772° C.), 3804 b(764° C.), 3804 c (753° C.), 3808 a (650° C.), 3808 b (591° C.), 3808 c(624° C.), and 3806 a (830° C.). When butane contacted the formation, itcracked to produce H₂, methane, ethane, ethene, propane, propylene, andcoke. FIG. 156 shows that as the butane injection rate increased, theproduction of H₂ 3970, methane 3972, ethane 3974, ethene 3976, propane3978, and propylene 3979 increased. This indicates that butane iscracking to form H₂ and lower molecular weight components.

FIG. 157 is a plot of the composition of gas (in volume percent)produced from the heated coal formation versus time in days at theexperimental field test. The species compositions included 3980-methane,3982-H₂, 3984-carbon dioxide, 3986-hydrogen sulfide, and 3988-carbonmonoxide. FIG. 157 shows a dramatic increase in the H₂ 3982concentration after about 150 days, or when synthesis as productionbegan.

Table 6 includes a composition of synthesis gas produced during a run ofthe in situ coal field experiment.

TABLE 6 Component Mol % Wt % Methane 12.263 12.197 Ethane 0.281 0.525Ethene 0.184 0.320 Acetylene 0.000 0.000 Propane 0.017 0.046 Propylene0.026 0.067 Propadiene 0.001 0.004 Isobutane 0.001 0.004 n-Butane 0.0000.001 I-Butene 0.001 0.003 Isobutene 0.000 0.000 cis-2-Butene 0.0050.018 trans-2-Butene 0.001 0.003 1,3-Butadiene 0.001 0.005 Isopentane0.001 0.002 n-Pentane 0.000 0.002 Pentene-1 0.000 0.000 T-2-Pentene0.000 0.000 2-Methyl-2-Butene 0.000 0.000 C-2-Pentene 0.000 0.000Hexanes 0.081 0.433 H₂ 51.247 6.405 Carbon monoxide 11.556 20.067 Carbondioxide 17.520 47.799 Nitrogen 5.782 10.041 Oxygen 0.955 1.895 Hydrogensulfide 0.077 0.163 Total 100.000 100.000

The experiment was performed in batch oxidation mode at about 620° C.The presence of nitrogen and oxygen is due to contamination of thesample with air. The mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, may bedetermined for the above data. For example, mole percent of H₂, carbonmonoxide, and carbon dioxide may be increased proportionally such thatthe mole percentages of the three components equals approximately 100%.In this manner, the mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, were 63.8%,14.4%, and 21.8%, respectively. The methane is believed to comeprimarily from the pyrolysis region outside the triangle of heaters.These values are in substantial agreement with the results ofequilibrium calculations shown in FIG. 159.

FIG. 159 is a plot of calculated equilibrium gas dry mole fractions fora coal reaction with water. Methane reactions are not included for FIGS.159-160. The fractions are representative of a synthesis gas that hasbeen produced from a hydrocarbon containing formation and has beenpassed through a condenser to remove water from the produced as.Equilibrium gas dry mole fractions are shown in FIG. 159 for H₂ 4000,carbon monoxide 4002, and carbon dioxide 4004 as a function oftemperature at a pressure of 2 bar absolute. As shown in FIG. 159, at390° C., liquid production tends to cease, and production of gases tendsto commence. The gases produced at this temperature include about 67%H₂, and about 33% carbon dioxide. Carbon monoxide is present innegligible quantities below about 410° C. At temperatures of about 500°C., however, carbon monoxide is present in the produced gas inmeasurable quantities. For example, at 500° C., about 66.5% H₂, about32% carbon dioxide, and about 2.5% carbon monoxide are present. At 700°C., the produced gals includes about 57.5% H₂, about 15.5% carbondioxide, and about 27% carbon monoxide.

FIG. 160 is a plot of calculated equilibrium wet mole fractions for acoal reaction with water. Equilibrium wet mole fractions are shown forwater 4006, H₂ 4008, carbon monoxide 4010, and carbon dioxide 4012 as afunction of temperature at a pressure of 2 bars absolute. At 390° C.,the produced gas includes about 89% water, about 7% H₂, and about 4%carbon dioxide. At 500° C., the produced gas includes about 66% water,about 22% H₂, about 11% carbon dioxide, and about 1% carbon monoxide. At700° C., the produced gas includes about 18% water, about 47.5% H₂,about 12% carbon dioxide, and about 22.5% carbon monoxide.

FIG. 159 and FIG. 160 illustrate that at the lower end of thetemperature range at which synthesis gas may be produced (i.e., about400° C.) equilibrium gas phase fractions may not favor production of H₂within a formation. As temperature increases, the equilibrium gas phasefractions increasingly favor the production of H₂. For example, as shownin FIG. 160, the gas phase equilibrium wet mole fraction of H₂ increasesfrom about 9% at 400° C. to about 39% at 610° C. and reaches 50% atabout 800° C. FIG. 159 and FIG. 160 further illustrate that attemperatures greater than about 660° C., equilibrium gas phase fractionstend to favor production of carbon monoxide over carbon dioxide.

FIG. 159 and FIG. 160 illustrate that as the temperature increases frombetween about 400° C. to about 1000° C., the H₂ to carbon monoxide ratioof produced synthesis gas may continuously decrease throughout thisrange. For example, as shown in FIG. 160, the equilibrium gas phase H₂to carbon monoxide ratio at 500° C., 660° C., and 1000° C. is about22:1, about 3:1, and about 1:1, respectively. FIG. 160 also indicatesthat produced synthesis gas at lower temperatures may have a largerquantity of water and carbon dioxide than at higher temperatures. As thetemperature increases, the overall percentage of carbon monoxide andhydrogen within the synthesis gas may increase.

FIG. 161 is a flowchart of an example of a pyrolysis stage 4020 andsynthesis gas production stage 4022 with heat and mass balances in highvolatile type A or B bituminous coal. In the pyrolysis stage 4020, heat4024 is supplied to the coal formation 4026. Liquid and gas products4028 and water 4030 exit the formation 4026. The portion of theformation subjected to pyrolysis is composed substantially of char afterundergoing pyrolysis heating Char refers to a solid carbonaceous residuethat results from pyrolysis of organic material. In the synthesis gasproduction stage 4022, steam 4032 and heat 4034 are supplied toformation 4036 that has undergone pyrolysis and synthesis gas 4038 isproduced.

In the embodiments of FIG. 161, the methane reactions in Equations (4)and (5) are included. The calculations set forth herein assume that charis only made of carbon and that there is an excess of carbon to steam.About 890 MW of energy 4024 is required to pyrolyze about 105,800 metrictons per day of coal. The pyrolysis products 4028 include liquids andgases with a production of 23,000 cubic meters per day. The pyrolysisprocess also produces about 7,160 metric tons per day of water 4030. Inthe synthesis gas stage about 57,800 metric tons per day of char withinjection of 23,000 metric tons per day of steam 4032 and 2,000 MW ofenergy 4034 with a 20% conversion will produce 12,700 cubic metersequivalent oil per day of synthesis gas 4038.

FIG. 162 is an example of a low temperature in situ synthesis gasproduction that occurs at a temperature of about 450° C. with heat andmass balances in a hydrocarbon containing formation that was previouslypyrolyzed. A total of about 42,900 metric tons per day of water isinjected into formation 4100 which may be char. FIG. 162 illustratesthat a portion of water 4102 at 25° C. is injected directly into theformation 4100. A portion of water 4102 is converted into steam 4104 ata temperature of about 130° C. and a pressure at about 3 bars absoluteusing about 1227 MW of energy 4106 and injected into formation 4100. Aportion of the remaining steam may be converted into steam 4108 at atemperature of about 450° C. and a pressure at about 3 bars absoluteusing about 318 MW of energy 4110. The synthesis gas production involvesabout 23% conversion of 13,137 metric tons per day of char to produce56.6 millions of cubic meters per day of synthesis gas with an energycontent of 5,230 MW. About 238 MW of energy 4112 is supplied toformation 4100 to account for the endothermic heat of reaction of thesynthesis gas reaction. The product stream 4114 of the synthesis gasreaction includes 29,470 metric tons per day of water at 46 volumepercent, 501 metric tons per day carbon monoxide at 0.7 volume percent,540 tons per day H₂ at 10.7 volume percent, 26,455 metric tons per daycarbon dioxide at 23.8 volume percent, and 7,610 metric tons per daymethane at 18.8 volume percent.

FIG. 163 is an example of a high temperature in situ synthesis gasproduction that occurs at a temperature of about 650° C. with heat andmass balances in a hydrocarbon containing formation that was previouslypyrolyzed. A total of about 34,352 metric tons per day of water isinjected into formation 4200. FIG. 163 illustrates that a portion ofwater 4202 at 25° C. is injected directly into formation 4200. A portionof water 4202 is converted into steam 4204 at a temperature of about130° C. and a pressure at about 3 bars absolute using about 982 MW ofenergy 4206, and injected into formation 4200. A portion of theremaining steam is converted into steam 4208 at a temperature of about650° C. and a pressure at about 3 bars absolute using about 413 MW ofenergy 4210. The synthesis gas production involves about 22% conversionof 12,771 metric tons per day of char to produce 56.6 millions of cubicmeters per day of synthesis gas with an energy content of 5,699 MW.About 898 MW of energy 4212 is supplied to formation 4200 to account forthe endothermic heat of reaction of the synthesis gas reaction. Theproduct stream 4214 of the synthesis gas reaction includes 10,413 metrictons per day of water at 22.8 volume percent, 9,988 metric tons per daycarbon monoxide at 14.1 volume percent, 1771 metric tons per day H₂ at35 volume percent, 21,410 metric tons per day carbon dioxide at 19.3volume percent, and 3535 metric tons per day methane at 8.7 volumepercent.

FIG. 164 is an example of an in situ synthesis gas production in ahydrocarbon containing formation with heat and mass balances. Synthesisgas generating fluid that includes water 4302 is supplied to theformation 4300. A total of about 22,000 metric tons per day of water isrequired for a low temperature process and about 24,000 metric tons perday is required for a high temperature process. A portion of the watermay be introduced into the formation as steam. Steam 4304 is produced bysupping heat to the water from an external source. About 7,119 metrictons per day of steam is provided for the low temperature process andabout 6913 metric tons per day of steam is provided for the hightemperature process.

At least a portion of the aqueous fluid 4306 exiting formation 4300 isrecycled 4308 back into the formation for generation of synthesis gas.For a low temperature process about 21,000 metric tons per day ofaqueous fluids is recycled and for a high temperature process about10,000 metric tons per day of aqueous fluids is recycled. The producedsynthesis gas 4310 includes carbon monoxide, H₂, and methane. Theproduced synthesis gas has a heat content of about 430,000 MMBtu per dayfor a low temperature process and a heat content of about 470,000 MMBtuper day for a low temperature process. Carbon dioxide 4312 produced inthe synthesis gas process includes about 26,500 metric tons per day inthe low temperature process and about 21,500 metric tons per day in thehigh temperature process. At least a portion of the produced synthesisas 4310 is used for combustion to heat the formation. There is about7,119 metric tons per day of carbon dioxide in the steam 4308 for thelow temperature process and about 6,913 metric tons per day of carbondioxide in the steam for the high temperature process. There is about2,551 metric tons per day of carbon dioxide in a heat reservoir for thelow temperature process and about 9,628 metric tons per day of carbondioxide in a heat reservoir for the high temperature process. There isabout 14,571 metric tons per day of carbon dioxide in the combustion ofsynthesis gas for the low temperature process and about 18,503 metrictons per day of carbon dioxide in produced combustion synthesis gas forthe high temperature process. The produced carbon dioxide has a heatcontent of about 60 gigaJoules (“GJ”) per metric ton for the lowtemperature process and about 6.3 GJ per metric ton for the hightemperature process.

Table 7 is an overview of the potential production volume ofapplications of synthesis gas produced by wet oxidation. The estimatesare based on 56.6 million standard cubic meters of synthesis gasproduced per day at 700° C.

TABLE 7 Production (main Application product) Power  2,720 MegawattsHydrogen  2,700 metric tons/day NH₃ 13,800 metric tons/day CH₄  7,600metric tons/day Methanol 13,300 metric tons/day Shell Middle  5,300metric tons/day Distillates

Experimental adsorption data has demonstrated that carbon dioxide may bestored in coal that has been pyrolyzed. FIG. 165 is a plot of thecumulative adsorbed methane and carbon dioxide in cubic meters permetric ton versus pressure in bar absolute at 25° C. on coal. The coalsample is sub-bituminous coal from Gillette, Wyoming. Data sets 4401,4402, 4403, 4404, and 4405 are for carbon dioxide adsorption on a posttreatment coal sample that has been pyrolyzed and has undergonesynthesis gas generation. Data set 4406 is for adsorption on anunpyrolyzed coal sample from the same formation. Data set 4401 isadsorption of methane at 25° C. Data sets 4402, 4403, 4404, and 4405 areadsorption of carbon dioxide at 25° C., 50° C., 100° C., and 150° C.,respectively. Data set 4406 is adsorption of carbon dioxide at 25° C. onthe unpyrolyzed coal sample. FIG. 165 shows that carbon dioxide attemperatures between 25° C. and 100° C. is more strongly adsorbed thanmethane at 25° C. in the pyrolyzed coal. FIG. 165 demonstrates that acarbon dioxide stream passed through post treatment coal tends todisplace methane from the post treatment coal.

Computer simulations have demonstrated that carbon dioxide may besequestered in both a deep coal formation and a post treatment coalformation. The Comet2 Simulator determined the amount of carbon dioxidethat could be sequestered in a San Juan Basin type deep coal formationand a post treatment coal formation. The simulator also determined theamount of methane produced from the San Juan Basin type deep coalformation due to carbon dioxide injection. The model employed for boththe deep coal formation and the post treatment coal formation was a 1.3km² area, with a repeating 5 spot well pattern. The 5 spot well patternincluded four injection wells arranged in a square and one productionwell at the center of the square. The properties of the San Juan Basinand the post treatment coal formations are shown in Table 8. Additionaldetails of simulations of carbon dioxide sequestration in deep coalformations and comparisons with field test results may be found in PilotTest Demonstrates How Carbon Dioxide Enhances Coal Bed Methane Recovery,Lanny Schoeling and Michael McGovern, Petroleum Technology Digest,September. 2000, p. 14-15.

TABLE 8 Post treatment coal Deep Coal Formation formation (Postpyrolysis (San Juan Basin) process) Coal Thickness  9  9 (m) Coal Depth(m) 990 460 Initial Pressure 114  2 (bars abs.) Initial  25° C.  25° C.Temperature Permeability (md) 5.5 (horiz.), 0 (vertical) 10,000(horiz.), 0 (vertical) Cleat porosity 0.2% 40%

The simulation model accounts for the matrix and dual porosity nature ofcoal and post treatment coal. For example, coal and post treatment coalare composed of matrix blocks. The spaces between the blocks are called“cleats”. Cleat porosity is a measure of available space for flow offluids in the formation. The relative permeabilities of gases and waterwithin the cleats required for the simulation were derived from fielddata from the San Juan coal. The same values for relative permeabilitieswere used in the post treatment coal formation simulations. Carbondioxide and methane were assumed to have the same relative permeability.

The cleat system of the deep coal formation was modeled as initiallysaturated with water. Relative permeability data for carbon dioxide andwater demonstrate that high water saturation inhibits absorption ofcarbon dioxide within cleats. Therefore, water is removed from theformation before injecting carbon dioxide into the formation.

In addition, the gases within the cleats may adsorb in the coal matrix.The matrix porosity is a measure of the space available for fluids toadsorb in the matrix. The matrix porosity and surface area were takeninto account with experimental mass transfer and isotherm adsorptiondata for coal and post treatment coal. Therefore, it is not necessary tospecify a value of the matrix porosity and surface area in the model.

The preferential adsorption of carbon dioxide over methane on posttreatment coal was incorporated into the model based on experimentaladsorption data. For example, FIG. 165 demonstrates that carbon dioxidehas a significantly higher cumulative adsorption than methane over anentire range of pressures at a specified temperature. Once the carbondioxide enters in the cleat system, methane diffuses out of and desorbsoff the matrix. Similarly, carbon dioxide diffuses into and adsorbs ontothe matrix. In addition, FIG. 165 also shows carbon dioxide may have ahigher cumulative adsorption on a pyrolyzed coal sample than anunpyrolyzed coal.

The pressure-volume-temperature (PVT) properties and viscosity requiredfor the model were taken from literature data for the pure componentgases.

The simulation modeled a sequestration process over a time period ofabout 3700 days for the deep coal formation model. Removal of the waterin the coal formation was simulated by production from all five wells.The production rate of water was about 40 m³/day for about the first 370days. The production rate of water decreased significantly after thefirst 370 days. It continued to decrease through the remainder of thesimulation run to about zero at the end. Carbon dioxide injection wasstarted at approximately 370 days at a flow rate of about 113,000standard (in this context “standard” means 1 atmosphere pressure and15.5 degrees Celsius) m³/day. The injection rate of carbon dioxide wasdoubled to about 226,000 standard m³/day at approximately 1440 days. Theinjection rate remained at about 226,000 standard m 3day until the endof the simulation run.

FIG. 177 illustrates the pressure at the wellhead of the injection wellsas a function of time during the simulation. The pressure decreased fromabout 114 bars absolute to about 19 bars absolute over the first 370days. The decrease in the pressure was due to removal of water from thecoal formation. Pressure then started to increase substantially ascarbon dioxide injection started at 370 days. The pressure reached amaximum of about 98 bars absolute. The pressure then began to graduallydecrease after 480 days. At about 1440 days, the pressure increasedagain to about 98 bars absolute due to the increase in the carbondioxide injection rate. The pressure gradually increased until about3640 days. The pressure jumped at about 3640 days because the productionwell was closed off.

FIG. 178 illustrates the production rate of carbon dioxide 5060 andmethane 5070 as a function of time in the simulation. FIG. 178 showsthat carbon dioxide was produced at a rate between about 0-10,000 m³/dayduring approximately the first 2400 days. The production rate of carbondioxide was significantly below the injection rate. Therefore, thesimulation predicts that most of the injected carbon dioxide is beingsequestered in the coal formation. However, at about 2400 days, theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the coal formation.

In addition, FIG. 178 shows that methane was desorbing as carbon dioxidewas adsorbing in the coal formation. Between about 370-2400 days, themethane production rate 5070 increased from about 60,000 to about115,000 standard m³/day. The increase in the methane production ratebetween about 1440-2400 days was caused by the increase in carbondioxide injection rate at about 1440 days. The production rate ofmethane started to decrease after about 2400 days. This was due to thesaturation of the coal formation. The simulation predicted a 50%breakthrough at about 2700 days. “Breakthrough” is defined as the ratioof the flow rate of carbon dioxide to the total flow rate of the totalproduced gas times 100%. Also, the simulation predicted about a 90%breakthrough at about 3600 days.

FIG. 179 illustrates cumulative methane produced 5090 and the cumulativenet carbon dioxide injected 5080 as a function of time during thesimulation. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 179 shows that by the end of the simulated injectionabout twice as much carbon dioxide was stored than methane produced. Inaddition, the methane production was about 0.24 billion standard m³ at50% carbon dioxide breakthrough. Also, the carbon dioxide sequestrationwas about 0.39 billion standard m³ at 50% carbon dioxide breakthrough.The methane production was about 0.26 billion standard m³ at 90% carbondioxide breakthrough. Also, the carbon dioxide sequestration was about0.46 billion standard m³ at 90% carbon dioxide breakthrough.

Table 8 shows that the permeability and porosity of the simulation inthe post treatment coal formation were both significantly higher than inthe deep coal formation prior to treatment. Also, the initial pressurewas much lower. The depth of the post treatment coal formation wasshallower than the deep coal bed methane formation. The same relativepermeability data and PVT data used for the deep coal formation wereused for the coal formation simulation. The initial water saturation forthe post treatment coal formation was set at 70%. Water was presentbecause it is used to cool the hot spent coal formation to 25° C. Theamount of methane initially stored in the post treatment coal is verylow.

The simulation modeled a sequestration process over a time period ofabout 3800 days for the post treatment coal formation model. Thesimulation modeled removal of water from the post treatment coalformation with production from all five wells. During about the first200 days, the production rate of water was about 680,000 standardm³/day. From about 200-3300 days the water production rate was betweenabout 210,000 to about 480,000 standard m³/day. Production rate of waterwas negligible after about 3300 days. Carbon dioxide injection wasstarted at approximately 370 days at a flow rate of about 113,000standard m³/day. The injection rate of carbon dioxide was increased toabout 226,000 standard m³/day at approximately 1440 days. The injectionrate remained at 226,000 standard m³/day until the end of the simulatedinjection.

FIG. 180 illustrates the pressure at the wellhead of the injection wellsas a function of time during the simulation of the post treatment coalformation model. The pressure was relatively constant up to about 370days. The pressure increased through most of the rest of the simulationrun up to about 36 bars absolute. The pressure rose steeply starting atabout 3300 days because the production well was closed off.

FIG. 181 illustrates the production rate of carbon dioxide as a functionof time in the simulation of the post treatment coal formation model.FIG. 181 shows that the production rate of carbon dioxide was almostnegligible during approximately the first 2200 days. Therefore, thesimulation predicts that nearly all of the injected carbon dioxide isbeing sequestered in the post treatment coal formation. However, atabout 2240 days, the produced carbon dioxide began to increase. Theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the post treatment coal formation.

FIG. 182 illustrates cumulative net carbon dioxide injected as afunction of time during the simulation in the post treatment coalformation model. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 182 shows that the simulation predicts a potential netsequestration of carbon dioxide of 0.56 Bm³. This value is greater thanthe value of 0.46 Bm³ at 90% carbon dioxide breakthrough in the deepcoal formation. However, comparison of FIG. 177 with FIG. 180 shows thatsequestration occurs at much lower pressures in the post treatment coalformation model. Therefore, less compression energy was required forsequestration in the post treatment coal formation.

The simulations show that large amounts of carbon dioxide may besequestered in both deep coal formations and in post treatment coalformations that have been cooled. Carbon dioxide may be sequestered inthe post treatment coal formation, in coal formations that have not beenpyrolyzed, and/or in both types of formations.

FIG. 166 is a flowchart of an embodiment of an in situ synthesis gasproduction process 4510 integrated with a SMDS Fischer-Tropsch and waxcracking process with heat and mass balances. The synthesis gasgenerating fluid injected into the formation includes about 24,000metric tons per day of water 4530, which includes about 5,500 metrictons per day of water 4540 recycled from the SMDS Fischer-Tropsch andwax cracking process 4520. A total of about 1700 MW of energy issupplied to the in situ synthesis gas production process 4510. About1020 MW of energy 4535 of the approximately 1700 MW of energy issupplied by in situ reaction of an oxidizing fluid with the formation,and approximately 680 MW of energy 4550 is supplied by the SMDSFischer-Tropsch and wax cracking process 4520 in the form of steam.About 12,700 cubic meters equivalent oil per day of synthesis gas 4560is used as feed gas to the SMDS Fischer-Tropsch and wax cracking process4520. The SMDS Fischer-Tropsch and wax cracking process 4520 producesabout 4,770 cubic meters per day of products 4570 that may includenaphtha, kerosene, diesel, and about 5,880 cubic meters equivalent oilper day of off gas 4580 for a power generation facility.

FIG. 167 is a comparison between numerical simulation and the in situexperimental coal field test composition of synthesis gas produced as afunction of time. The plot excludes nitrogen and traces of oxygen thatwere contaminants during gas sampling. Symbols represent experimentaldata and curves represent simulation results. Hydrocarbons 4601 aremethane since all other heavier hydrocarbons have decomposed at theprevailing temperatures. The simulation results are moving averages ofraw results, which exhibit peaks and troughs of approximately ±10percent of the averaged value. In the model, the peaks of H₂ occurredwhen fluids were injected into the coal seam, and coincided with lows inCO₂ and CO.

The simulation of H₂ 4604 provides a good fit to observed fraction of H₂4603. The simulation of methane 4602 provides a good fit to observedfraction of methane 4601. The simulation of carbon dioxide 4606 providesa good fit to observed fraction of carbon dioxide 4605. The simulationof CO 4608 overestimated the fraction of CO 4607 by 4-5 percentagepoints. Carbon monoxide is the most difficult of the synthesis gascomponents to model. Also, the carbon monoxide discrepancy may be due tofact that the pattern temperatures exceeded 550° C., the upper limit atwhich the numerical model was calibrated.

Other methods of producing synthesis gas were successfully demonstratedat the experimental field test. These included continuous injection ofsteam and air, steam and oxygen, water and air, water and oxygen, steam,air and carbon dioxide. All these injections successfully generatedsynthesis gas in the hot coke formation.

Low temperature pyrolysis experiments with tar sand were conducted todetermine a pyrolysis temperature zone and effects of temperature in aheated portion on the quality of the produced pyrolization fluids. Thetar sand was collected from the Athabasca tar sand region. FIG. 89depicts a retort and collection system used to conduct the experiment.The retort and collection may be configured as described herein.

Laboratory experiments were conducted on three tar samples contained intheir natural sand matrix. The three tar samples were collected from theAthabasca tar sand region in western Canada. In each case, core materialreceived from a well was mixed and then was split. One aliquot of thesplit core material was used in the retort, and the replicate aliquotwas saved for comparative analyses. Materials sampled included a tarsample within a sandstone matrix.

The heating rate for the runs was varied at 1° C/day, 5° C/day, and 10°C./day. The pressure condition was varied for the runs at pressures of 1bar, 7.9 bars, and 28.6 bars. Run #78 was operated with no backpressure1 bar absolute and a heating rate of 1° C/day. Run #79 was operated withno backpressure 1 bar absolute and a heating rate of 5° C./day. Run #81was operated with no backpressure 1 bar absolute and a heating rate of10° C./day. Run #86 was operated with at a pressure of 7.9 bars absoluteand a heating rate of 10° C./day. Run #96 was operated with at apressure of 28.6 bars absolute and a heating rate of 10° C./day. Ingeneral, 0.5 to 1.5 kg initial weight of the sample was required to fillthe available retort cells.

The internal temperature for the runs was raised from ambient to 110°C., 200° C., 225° C. and 270° C. with 24 hours holding time between eachtemperature increase. Most of the moisture was removed from the samplesduring this heating. Beginning at 270° C., the temperature was increasedby 1° C./day, 5° C./day, or 10° C./day until no further fluid wasproduced. The temperature was monitored and controlled during theheating of this stage.

Produced liquid was collected in graduated glass collection tubes.Produced gas was collected in graduated glass collection bottles. Fluidvolumes were read and recorded daily. Accuracy of the oil and gas volumereadings was within +/−0.6% and 2%, respectively. The experiments werestopped when fluid production ceased. Power was turned off and more than12 hours was allowed for the retort to fall to room temperature. Thepyrolyzed sample remains were unloaded, weighed, and stored in sealedplastic cups. Fluid production and remaining rock material were sent outfor analytical experimentation.

In addition, Dean Stark toluene solvent extraction was used to assay theamount of tar contained in the sample. In such an extraction procedure,a solvent such as toluene or a toluene/xylene mixture may be mixed witha sample and may be refluxed under a condenser using a receiver. As therefluxed sample condenses, two phases of the sample may separate as theyflow into the receiver. For example, tar may remain in the receiverwhile the solvent returns to the flask. Detailed procedures for DeanStark toluene solvent extraction are provided by the American Societyfor Testing and Materials (“ASTM”). The ASTM is incorporated byreference as if fully set forth herein. A 30 g sample from each depthwas sent for Dean Stark extraction analysis.

Table 9 illustrates the elemental analysis of initial tar and of theproduced fluids for runs #81, #86, and #96. These data are all for aheating rate of 10° C./day. Only a pressure was varied between the runs.

TABLE 9 C H N Run # P (bar) (wt %) (wt %) (wt %) O (wt %) S (wt %)Initial Tar — 76.58 11.28 1.87 5.96 4.32 81 1 85.31 12.17 0.08 — 2.47 8679 81.78 11.69 0.06 4.71 1.76 96 28.6 82.68 11.65 0.03 4.31 1.33

As illustrated in Table 9, pyrolysis of the tar sand decreases nitrogenand sulfur weight percentages in a produced fluid and increases carbonweight percentage in a produced fluid. Increasing the pressure in thepyrolysis experiment appears to further decrease the nitrogen and sulfurweight percentage in the produced fluids.

Table 10 illustrates NOISE (Nitric Oxide Ionization SpectrometryEvaluation) analysis data for runs #81, #86, and #96 and the initialtar. NOISE has been developed by a commercial laboratory as aquantitative analysis of the weight percentages of the main constituentsin oil. The remaining weight percentage (47.2%) in the initial tar maybe found in a residue.

TABLE 10 P Paraffins Cycloalkanes Phenols Mono-aromatics Run # (bar) (wt%) (wt %) (wt %) (wt %) Initial — 7.08 29.15 0 6.73 Tar 81 1 15.36 46.70.34 21.04 86 7.9 27.16 45.8 0.54 16.88 96 28.6 26.45 36.56 0.47 28.0Di-aromatics Tri-aromatics Tetra-aromatics Run # P (bar) (wt %) (wt %)(wt %) Initial Tar — 8.12 1.70 0.02 81 1 14.83 1.72 0.01 86 7.9 9.090.53 0 96 28.6 8.52 0 0

As illustrated in Table 10, pyrolyzation of tar sand produces a productfluid with a significantly higher weight percentage of paraffins,cycloalkanes, and mono-aromatics than may be found in the initial tarsand. Increasing the pressure up to 7.9 bars absolute appears tosubstantially eliminate the production of tetra-aromatics. Furtherincreasing the pressure up to 28.6 bars absolute appears tosubstantially eliminate the production of tri-aromatics. An increase inthe pressure also appears to decrease a production of di-aromatics.Increasing the pressure up to 28.6 bars absolute also appears tosignificantly increase a production of mono-aromatics. This may be dueto an increased hydrogen partial pressure at the higher pressure. Theincreased hydrogen partial pressure may reduce poly-aromatic compoundsto the mono-aromatics.

FIG. 168 illustrates plots of weight percentages of carbon compoundsversus carbon number for initial tar 4703 and runs at pressures of 1 barabsolute 4704, 7.9 bars absolute 4705, and 28.6 bars absolute 4706 witha heating rate of 10° C./day. From the plots of initial tar 4703 and apressure of 1 bar absolute 4704 it can be seen that pyrolysis shifts anaverage carbon number distribution to relatively lower carbon numbers.For example, a mean carbon number in the carbon distribution of plot4703 is at about carbon number nineteen and a mean carbon number in thecarbon distribution of plot 4704 is at about carbon number seventeen.Increasing the pressure to 7.9 bars absolute 4705 further shifts theaverage carbon number distribution to even lower carbon numbers.Increasing the pressure to 7.9 bars absolute 4705 also shifts the meancarbon number in the carbon distribution to a carbon number of aboutthirteen. Further increasing the pressure to 28.6 bars absolute 4706reduces the mean carbon number to about eleven. Increasing the pressureis believed to decrease the average carbon number distribution byincreasing a hydrogen partial pressure in the product fluid. Theincreased hydrogen partial pressure in the product fluid allowshydrogenation, dearomatization, and/or pyrolysis of large molecules toform smaller molecules. Increasing the pressure also increases a qualityof the produced fluid. For example, the API gravity of the fluidincreased from less than about 100 for the initial tar, to about 31° fora pressure of 1 bar absolute, to about 390 for a pressure of 7.9 barsabsolute, to about 45° for a pressure of 28.6 bars absolute.

FIG. 169 illustrates bar graphs of weight percentages of carboncompounds for various pyrolysis heating rates and pressures. Bar graph4710 illustrates weight percentages for pyrolysis with a heating rate of1° C./day at a pressure of 1 bar absolute. Bar graph 4712 illustratesweight percentages for pyrolysis with a heating rate of 5° C./day at apressure of 1 bar absolute. Bar graph 4714 illustrates weightpercentages for pyrolysis with a heating rate of 10° C./day at apressure of 1 bar absolute. Bar graph 4716 illustrates weightpercentages for pyrolysis with a heating rate of 10° C./day at apressure of 7.9 bars absolute. Weight percentages of paraffins 4720,cycloalkanes 4722, mono-aromatics 4724, di-aromatics 4726, andtri-aromatics 4728 are illustrated in the bar graphs. The bar graphsdemonstrate that a variation in the heating rate between 1° C./day to10° C./day does not significantly affect the composition of the productfluid. Increasing the pressure from 1 bar absolute to 7.9 bars absolute,however, affects a composition of the product fluid. Such an effect maybe characteristic of the effects described in FIG. 168 and Tables 9 and10 above.

A three-dimensional (3-D) simulation model was used to simulate an insitu conversion process for a tar sand formation. A heat injection ratewas calculated using a separate numerical code (CFX; AEA Technology,Oxfordshire, UK). The heat injection rate was calculated at 500 wattsper foot (1640 watts per meter). The 3-D simulation was based on adilation-recompaction model for tar sands. A target zone thickness of 50meters was used. Input data for the simulation were based on averagereservoir properties of the Grosmont formation in northern Alberta,Canada as follows:

Depth of target zone=280 meters;

Thickness=50 meters;

Porosity=0.27;

Oil saturation=0.84;

Water saturation=0.16;

Permeability=1000 millidarcy;

Vertical permeability versus horizontal permeability=0.1;

Overburden=shale; and

Base rock=wet carbonate.

Six component fluids were used based on fluids found in Athabasca tarsands. The six component fluids were: heavy fluid; light fluid; gas;water; pre-char; and char. The spacing between wells was set at 9.1meters on a triangular pattern. Eleven horizontal heaters with a 300 mheater length were used with heat outputs set at the previouslycalculated value of 1640 watts per meter.

FIG. 170 illustrates a plot of oil production (in cubic meters) versustime (in days) for various bottomhole pressures at a producer well. Plot4742 illustrates oil production for a pressure of 1.03 bars absolute.Plot 4740 illustrates oil production for a pressure of 6.9 barsabsolute. FIG. 170 demonstrates that increasing the bottomhole pressurewill decrease oil production in a tar sand formation.

FIG. 171 illustrates a plot of a ratio of heat content of producedfluids from a reservoir against heat input to heat the reservoir versustime (in days). Plot 4752 illustrates the ratio versus time for heatingan entire reservoir to a pyrolysis temperature. Plot 4750 illustratesthe ratio versus time for allowing partial drainage in the reservoirinto a selected pyrolyzation section. FIG. 171 demonstrates thatallowing partial drainage in the reservoir tends to increase the heatcontent of produced fluids versus heating the entire reservoir, for agiven heat input into the reservoir.

FIG. 172 illustrates a plot of weight percentage versus carbon numberdistribution for the simulation. Plot 4760 illustrates the carbon numberdistribution for the initial tar sand. The initial tar sand has an APIgravity of 6°. Plot 4762 illustrates the carbon number distribution forin situ conversion of the tar sand up to a temperature of 350° C. Plot4762 has an API gravity of 30°. From FIG. 172, it can be seen that thein situ conversion process substantially increases the quality of oilfound in the tar sands, as evidenced by the increased API gravity andthe carbon number distribution shift to lower carbon numbers. The lowercarbon number distribution was also evidenced by the result showing thata majority of the produced fluid was produced as a vapor.

FIG. 102 illustrates a tar sand drum experimental apparatus used toconduct an experiment. Drum 3400 was filled with Athabasca tar sand andheated. All experiments were conducted using the system shown in FIG.102 (see other description herein). Vapors were produced from the drum,cooled, separated into liquids and gases, and then analyzed. Twoseparate experiments were conducted, each using tar sand from the samebatch, but the drum pressure was maintained at 1 bar absolute in oneexperiment (the low pressure experiment), and the drum pressure wasmaintained at 6.9 bars absolute in the other experiment (the highpressure experiment). The drum pressures were allowed to autogenouslyincrease to the maintained pressure as temperatures were increased.

FIG. 173 illustrates mole % of hydrogen in the gases during theexperiment (i.e., when the drum temperature was increased at the rate of2 degrees Celsius per day). Line 4770 illustrates results obtained whenthe drum pressure was maintained at 1 bar absolute. Line 4772illustrates results obtained when the drum pressure was maintained at6.9 bars absolute. FIG. 173 demonstrates that a higher mole percent ofhydrogen was produced in the gas when the drum was maintained at lowerpressures. It is believed that increasing the drum pressure drovehydrogen into the liquids in the drum. The hydrogen will tend tohydrogenate heavy hydrocarbons.

FIG. 174 illustrates API gravity of liquids produced from the drum astemperature was increased in the drum. Line 4782 depicts results fromthe high pressure experiment and line 4780 depicts results from the lowpressure experiment. As illustrated in FIG. 174, higher quality liquidswere produced at the higher drum pressure. It is believed that higherquality liquids were produced because more hydrogenation occurred in thedrum during the high pressure experiment (although the hydrogenconcentration in the gas was less in the high pressure experiment, thedrum pressures were significantly greater, and therefore the partialpressure of hydrogen in the drum was greater in the high pressureexperiment).

Further modifications and alternative embodiments of various aspects ofthe invention may be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as the presently preferred embodiments. Elements andmaterials may be substituted for those illustrated and described herein,parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements describe herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims.

What is claimed is:
 1. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from heaters to at least aportion of the formation; allowing the heat to transfer from the heatersto a part of the formation such that superimposed heat from the heaterspyrolyzes at least about 20% by weight of hydrocarbons within the partof the formation; and producing a mixture from the formation.
 2. Themethod of claim 1, wherein the heaters comprise at least two heaters,and wherein superposition of heat from at least the two heaterspyrolyzes at least some hydrocarbons within the part of the formation.3. The method of claim 1, further comprising maintaining a temperaturewithin the part within a pyrolysis temperature range.
 4. The method ofclaim 1, wherein at least one of the heaters comprises an electricalheater.
 5. The method of claim 1, wherein at least one of the heaterscomprises a surface burner.
 6. The method of claim 1, wherein at leastone of the heaters comprises a flameless distributed combustor.
 7. Themethod of claim 1, wherein at least one of the heaters comprises anatural distributed combustor.
 8. The method of claim 1, furthercomprising controlling a pressure and a temperature within at least amajority of the part of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 9. The method of claim 1, furthercomprising controlling the heat such that an average heating rate of thepart is less than about 1° C. per day during pyrolysis.
 10. The methodof claim 1, wherein providing heat from the heaters to at least theportion of the formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the heaters, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day (Pwr) provided to the selected volume isequal to or less than h*V*C_(V)*ρ_(B), wherein ρ_(B) is formation bulkdensity, and wherein an average heating rate of the selected volume (h)is about 10° C./day.
 11. The method of claim 1, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 12. The method of claim 1, wherein providing heat from theheaters comprises heating the selected formation such that a thermalconductivity of at least a portion of the part is greater than about 0.5W/(m ° C.).
 13. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 14. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins.
 15. Themethod of claim 1, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 16. Themethod of claim 1, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethane toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 17. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 18. The method of claim 1, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 19. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 20. The method of claim 1, whereinthe produced mixture comprises condensable hydrocarbons, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 21. The method of claim 1, wherein theproduced mixture comprises condensable hydrocarbons, and wherein greaterthan about 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 22. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 23. The method of claim 1, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 24. The method of claim 1, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.25. The method of claim 1, wherein the produced mixture comprises anon-condensable component wherein the non-condensable componentcomprises molecular hydrogen, wherein the molecular hydrogen is greaterthan about 10% by volume of the non-condensable component, and whereinthe molecular hydrogen is less than about 80% by volume of thenon-condensable component.
 26. The method of claim 1, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 27. The method of claim 1,wherein the produced mixture comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 28. The method of claim 1, furthercomprising controlling a pressure within at least a majority of the partof the formation, wherein the controlled pressure is at least about 2.0bar absolute.
 29. The method of claim 1, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 30. The method of claim 1, wherein a partialpressure of H₂ is measured when the mixture is at a production well. 31.The method of claim 1, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 32. The method of claim 29,wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 33. The methodof claim 1, further comprising: providing hydrogen (H₂) to the heatedpart to hydrogenate hydrocarbons within the part; and heating a portionof the part with heat from hydrogenation.
 34. The method of claim 1,wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 35. The method of claim 1, wherein allowing the heatto transfer increases a permeability of a majority of the part togreater than about 100 millidarcy.
 36. The method of claim 1, whereinallowing the heat to transfer comprises increases a permeability of amajority of the part such that the permeability of the majority of thepart is substantially uniform.
 37. The method of claim 1, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by the Fischer Assay.38. The method of claim 1, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heaters are disposed in the formation for each production well.
 39. Themethod of claim 1, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, andwherein the unit of heaters comprises a triangular pattern.
 40. Themethod of claim 1, further comprising providing heat from three or moreheaters to at least a portion of the formation, wherein three or more ofthe heaters are located in the formation in a unit of heaters, whereinthe unit of heaters comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 41. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom heat sources to at least a portion of the formation; allowing theheat to transfer from the heat sources to a part of the formation suchthat superimposed heat from the heat sources pyrolyzes at least about20% of hydrocarbons within the part of the formation; and producing amixture from the formation, wherein the mixture comprises a condensablecomponent having an API gravity of at least about 25°.
 42. The method ofclaim 41, wherein the heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the part of the formation.43. The method of claim 41, further comprising maintaining a temperaturewithin the part within a pyrolysis temperature range.
 44. The method ofclaim 41, wherein at least one of the heat sources comprises anelectrical heater.
 45. The method of claim 41, wherein at least one ofthe heat sources comprises a surface burner.
 46. The method of claim 41,wherein at least one of the heat sources comprises a flamelessdistributed combustor.
 47. The method of claim 41, wherein at least oneof the heat sources comprises a natural distributed combustor.
 48. Themethod of claim 41, further comprising controlling a pressure and atemperature within at least a majority of the part of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 49. The method ofclaim 41, further comprising controlling the heat such that an averageheating rate of the part is less than about 1° C. per day duringpyrolysis.
 50. The method of claim 41, wherein providing heat from theheat sources to at least the portion of the formation comprises: heatinga selected volume (ν) of the hydrocarbon containing formation from theheat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day (Pwr) provided to the selected volume is equal to or lessthan h*V*C_(V)*ρ_(B), wherein ρ_(B) is formation bulk density, andwherein an average heating rate of the selected volume (h) is about 10°C./day.
 51. The method of claim 41, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 52.The method of claim 41, wherein providing heat from the heat sourcescomprises heating the part such that a thermal conductivity of at leasta portion of the part is greater than about 0.5 W/(m ° C.).
 53. Themethod of claim 41, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 54. The method of claim 41,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 55. The method of claim 41,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 56. The method ofclaim 41, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen.
 57. Themethod of claim 41, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 58. Themethod of claim 41, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 59. Themethod of claim 41, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 60. The methodof claim 41, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 61. The method of claim41, wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 62. The methodof claim 41, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 63. The method of claim 41,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 64. The method of claim 41, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises molecular hydrogen wherein themolecular hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the molecular hydrogen is lessthan about 80% by volume of the non-condensable component.
 65. Themethod of claim 41, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 66. The method of claim 41, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 67. The method claim 41, further comprising controlling apressure within at least a majority of the part of the formation,wherein the controlled pressure is at least about 2.0 bar absolute. 68.The method of claim 41, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bar.
 69. The method of claim 41, wherein a partial pressure ofH₂ is measured when the mixture is at a production well.
 70. The methodof claim 41, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 71. The method of claim 68, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 72. The method of claim41, further comprising: providing hydrogen (H₂) to the part tohydrogenate hydrocarbons within the part; and heating a portion of thepart with heat from hydrogenation.
 73. The method of claim 41, whereinthe produced mixture comprises hydrogen and condensable hydrocarbons,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 74. The method of claim 41, wherein allowing the heat totransfer increases a permeability of a majority of the part to greaterthan about 100 millidarcy.
 75. The method of claim 41, wherein allowingthe heat to transfer increases a permeability of a majority of the partsuch that the permeability of the majority of the part is substantiallyuniform.
 76. The method of claim 41, further comprising controlling theheat to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay.
 77. The method of claim41, wherein producing the mixture comprises producing the mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 78. The method of claim 41,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern.
 79. Themethod of claim 41, further comprising providing heat from three or moreheat sources to at least a portion of the formation, wherein three ormore of the heat sources are located in the formation in a unit of heatsources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 80. The methodof claim 38, wherein at least about 20 heaters are disposed in theformation for each production well.
 81. The method of claim 77, whereinat least about 20 heat sources are disposed in the formation for eachproduction well.
 82. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from heat sources to atleast a portion of the formation, wherein at least one of the heatsources comprises a natural distributed combustor; allowing the heat totransfer from the heat sources to a part of the formation such thatsuperimposed heat from the heat sources pyrolyzes at least about 20% ofhydrocarbons within the part of the formation; and producing a mixturefrom the formation.
 83. The method of claim 82, further comprisingmaintaining a temperature within the part in a pyrolysis temperaturerange.
 84. The method of claim 82, further comprising controlling apressure and a temperature in at least a majority of the part of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.85. The method of claim 82, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.86. The method of claim 82, further comprising controlling a pressurewithin at least a majority of the part of the formation, wherein thecontrolled pressure is at least about 2.0 bars absolute.
 87. The methodof claim 82, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 88. The method of claim 82, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons in the part of the formation, asmeasured by the Fischer Assay.
 89. The method of claim 82, wherein theheat is allowed to transfer from the heat sources to at least a portionof the part of the formation to establish a pyrolysis zone in the partof the formation.
 90. The method of claim 82, wherein the heat isallowed to transfer from the heat sources to at least a portion of thepart of the formation to establish a pyrolysis zone proximate to and/orsurrounding at least one heat source in the part of the formation.
 91. Amethod of treating a hydrocarbon containing formation in situ,comprising: providing heat from heat sources to at least a portion ofthe formation; allowing the heat to transfer from the heat sources to apart of the formation such that superimposed heat from the heat sourcespyrolyzes at least about 20% of hydrocarbons within the part of theformation; altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about 25; and producing a mixture from the formation. 92.The method of claim 91, further comprising maintaining a temperaturewithin the part in a pyrolysis temperature range.
 93. The method ofclaim 91, further comprising controlling a pressure and a temperaturewithin at least a majority of the part of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 94. The method of claim 91,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 95. The method of claim 91,further comprising controlling a pressure within at least a majority ofthe part of the formation, wherein the controlled pressure is at leastabout 2.0 bar absolute.
 96. The method of claim 91, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons in the part of the formation, as measured bythe Fischer Assay.
 97. The method of claim 91, wherein the heat isallowed to transfer from the heat sources to at least a portion of thepart of the formation to establish a pyrolysis zone in the part of theformation.
 98. The method of claim 91, wherein the heat is allowed totransfer from the heat sources to at least a portion of the part of theformation to establish a pyrolysis zone proximate to and/or surroundingat least one heat source in the part of the formation.
 99. The method ofclaim 91, wherein the heat sources comprise heaters.
 100. The method ofclaim 91, wherein at least one of the heat sources comprises a heater.101. A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from heat sources to at least a portion ofthe formation; allowing the heat to transfer from the heat sources to apart of the formation such that superimposed heat from the heat sourcespyrolyzes at least about 20% by weight of hydrocarbons within the partof the formation; and producing a mixture from the formation, wherein apartial pressure of H₂ is measured when the mixture is at a productionwell.
 102. The method of claim 101, further comprising maintaining atemperature within the part in a pyrolysis temperature range.
 103. Themethod of claim 101, further comprising controlling a pressure and atemperature in at least a majority of the part of the formation, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 104. The method ofclaim 101, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 105. Themethod of claim 101, further comprising controlling a pressure within atleast a majority of the part of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 106. The method of claim101, further comprising altering a pressure within the formation toinhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 107. The method of claim 101, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons in the part of the formation, asmeasured by the Fischer Assay.
 108. The method of claim 101, wherein theheat sources comprise heaters.
 109. The method of claim 101, wherein atleast one of the heat sources comprises a heater.
 110. The method ofclaim 101, wherein the heat is allowed to transfer from the heat sourcesto at least a portion of the part of the formation to establish apyrolysis zone in the part of the formation.
 111. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom heat sources to at least a portion of the formation; allowing theheat to transfer from the heat sources to a part of the formation suchthat superimposed heat from the heat sources pyrolyzes at least about20% by weight of hydrocarbons within the part of the formation;producing a mixture from the formation, wherein the mixture compriseshydrogen; and recirculating a portion of hydrogen from the mixture intothe formation.
 112. The method of claim 111, further comprisingmaintaining a temperature within the part in a pyrolysis temperaturerange.
 113. The method of claim 111, further comprising controlling apressure and a temperature in at least a majority of the part of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.114. The method of claim 111, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.115. The method of claim 111, further comprising controlling a pressurewithin at least a majority of the part of the formation, wherein thecontrolled pressure is at least about 2.0 bars absolute.
 116. The methodof claim 111, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 117. The method of claim111, further comprising controlling the heat to yield greater than about60% by weight of condensable hydrocarbons in the part of the formation,as measured by the Fischer Assay.
 118. The method of claim 111, whereinthe heat sources comprise heaters.
 119. The method of claim 111, whereinat least one of the heat sources comprises a heater.
 120. The method ofclaim 111, wherein the heat is allowed to transfer from the heat sourcesto at least a portion of the part of the formation to establish apyrolysis zone in the part of the formation.
 121. The method of claim111, wherein the heat is allowed to transfer from the heat sources to atleast a portion of the part of the formation to establish a pyrolysiszone proximate to and/or surrounding at least one heat source in thepart of the formation.
 122. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from heatsources to at least a portion of the formation; allowing the heat totransfer from the heat sources to a part of the formation such thatsuperimposed heat from the heat sources pyrolyzes at least about 20% byweight of hydrocarbons within the part of the formation; providinghydrogen (H₂) to the heated part to hydrogenate hydrocarbons within thepart; heating a portion of the section with heat from hydrogenation; andproducing a mixture from the formation.
 123. The method of claim 122,further comprising maintaining a temperature within the part in apyrolysis temperature range.
 124. The method of claim 122, furthercomprising controlling a pressure and a temperature in at least amajority of the part of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 125. The method of claim 122,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 126. The method of claim 122,further comprising controlling a pressure within at least a majority ofthe part of the formation, wherein the controlled pressure is at leastabout 2.0 bars absolute.
 127. The method of claim 122, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 128. The method of claim 122, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons in the part of the formation, as measured bythe Fischer Assay.
 129. The method of claim 122, wherein the heatsources comprise heaters.
 130. The method of claim 122, wherein at leastone of the heat sources comprises a heater.
 131. The method of claim122, wherein the heat is allowed to transfer from the heat sources to atleast a portion of the part of the formation to establish a pyrolysiszone in the part of the formation.
 132. The method of claim 122, whereinthe heat is allowed to transfer from the heat sources to at least aportion of the part of the formation to establish a pyrolysis zoneproximate to and/or surrounding at least one beat source in thee part ofthe formation.
 133. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from heat sources to atleast a portion of the formation; allowing the heat to transfer from theheat sources to a part of the formation such that superimposed heat fromthe heat sources pyrolyzes at least about 20% by weight of hydrocarbonswithin the part of the formation; producing a mixture from theformation, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons; and hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 134. The method of claim 133, further comprising maintaining atemperature within the part in a pyrolysis temperature range.
 135. Themethod of claim 133, further comprising controlling a pressure and atemperature in at least a majority of the part of the formation, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 136. The method ofclaim 133, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 137. Themethod of claim 133, further comprising controlling a pressure within atleast a majority of the part of the formation, wherein the controlledpressure is at least about 2.0 bars absolute.
 138. The method of claim133, further comprising altering a pressure within the formation toinhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 139. The method of claim 133, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons in the part of the formation, asmeasured by the Fischer Assay.
 140. The method of claim 133, wherein theheat sources comprise heaters.
 141. The method of claim 133, wherein atleast one of the heat sources comprises a heater.
 142. The method ofclaim 133, wherein the heat is allowed to transfer from the heat sourcesto at least a portion of the part of the formation to establish apyrolysis zone in the part of the formation.
 143. The method of claim133, wherein the heat is allowed to transfer from the heat sources to atleast a portion of the part of the formation to establish a pyrolysiszone proximate to and/or surrounding at least one heat source in thepart of the formation.
 144. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from heaters toat least a portion of the formation; allowing the heat to transfer fromthe heaters to a part of the formation such that superimposed heat fromthe heaters pyrolyzes at least about 20% by weight of hydrocarbonswithin the part of the formation; and producing the mixture using aproduction well, and wherein at least about 7 heaters are disposed inthe formation for each production well.
 145. The method of claim 144,further comprising maintaining a temperature within the part in apyrolysis temperature range.
 146. The method of claim 144, furthercomprising controlling a pressure and a temperature in at least amajority of the part of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 147. The method of claim 144,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 148. The method of claim 144,further comprising controlling a pressure within at least a majority ofthe part of the formation, wherein the controlled pressure is at leastabout 2.0 bars absolute.
 149. The method of claim 144, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 150. The method of claim 144, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons in the part of the formation, as measured bythe Fischer Assay.
 151. The method of claim 144, wherein the heat isallowed to transfer from the heaters to at least a portion of the partof the formation to establish a pyrolysis zone in the part of theformation.
 152. The method of claim 144, wherein the heat is allowed totransfer from the heaters to at least a portion of the part of theformation to establish a pyrolysis zone proximate to and/or surroundingat least one heater in the part of the formation.
 153. The method ofclaim 1, wherein the heat is allowed to transfer from the heaters to atleast a portion of the part of the formation to establish a pyrolysiszone in the part of the formation.
 154. The method of claim 1, whereinthe heat is allowed to transfer from the heaters to at least a portionof the part of the formation to establish a pyrolysis zone proximate toand/or surrounding at least one heater in the part of the formation.155. The method of claim 41, wherein the heat is allowed to transferfrom the heat sources to at least a portion of the part of the formationto establish a pyrolysis zone in the part of the formation.
 156. Themethod of claim 41, wherein the heat is allowed to transfer from theheat sources to at least a portion of the part of the formation toestablish a pyrolysis zone proximate to and/or surrounding at least oneheat source in the part of the formation.